UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

For the quarterly period ended March 31, 2016

OR

For the transition period from              to             

Commission file number: 333-134748

 

Chaparral Energy, Inc.

(Exact name of registrant as specified in its charter)

 

 

 

(405) 478-8770

(Registrant’s telephone number, including area code)

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  o    No  x

(Explanatory Note: The registrant is a voluntary filer and is not subject to the filing requirements of the Securities Exchange Act of 1934.)

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  o    No  x

Number of shares outstanding of each of the issuer’s classes of common stock as of May 13, 2016:

 

 

 

 

 

 

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CHAPARRAL ENERGY, INC.

Index to Form 10-Q

 

 

 

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This report includes statements that constitute forward-looking statements within the meaning of the federal securities laws. These statements are subject to risks and uncertainties. These statements may relate to, but are not limited to, information or assumptions about us, our capital and other expenditures, dividends, financing plans, capital structure, cash flow, pending legal and regulatory proceedings and claims, including environmental matters, future economic performance, operating income, cost savings, and management’s plans, strategies, goals and objectives for future operations and growth. These forward-looking statements generally are accompanied by words such as “intend,” “anticipate,” “believe,” “estimate,” “expect,” “should,” “seek,” “project,” “plan” or similar expressions. Any statement that is not a historical fact is a forward-looking statement. It should be understood that these forward-looking statements are necessarily estimates reflecting the best judgment of senior management, not guarantees of future performance. They are subject to a number of assumptions, risks and uncertainties that could cause actual results to differ materially from those expressed or implied in the forward-looking statements. Forward-looking statements in this report may include, for example, statements about:

These forward-looking statements represent intentions, plans, expectations, assumptions and beliefs about future events and are subject to risks, uncertainties and other factors. Many of those factors are outside of our control and could cause actual results to differ materially from the results expressed or implied by those forward-looking statements. These risks and uncertainties include those factors described in Item 1A of this report and under the heading “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2015. Specifically, some factors that could cause actual results to differ include:

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Should one or more of these risks or uncertainties materialize, or should any of our assumptions prove incorrect, actual results may vary in material respects from those projected in the forward-looking statements contained herein. We undertake no obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. All forward-looking statements included herein are expressly qualified in their entirety by the cautionary statements contained or referred to in this section.

GLOSSARY OF OIL AND NATURAL GAS TERMS

The terms defined in this section are used throughout this Form 10-Q:

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PART I — FINANCIAL INFORMATION

Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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Chaparral Energy, Inc. and subsidiaries

Consolidated balance sheets—continued

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of operations

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of cash flows

 

 

The accompanying notes are an integral part of these consolidated financial statements.

 

 

 

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited)

(dollars in thousands, unless otherwise noted)

 

 

Note 1: Nature of operations and summary of significant accounting policies

Nature of operations

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

Interim financial statements

The accompanying unaudited consolidated interim financial statements of the Company have been prepared in accordance with the rules and regulations of the SEC and do not include all of the financial information and disclosures required by accounting principles generally accepted in the United States of America (“GAAP”) for complete financial statements. These financial statements and the notes thereto should be read in conjunction with our Annual Report on Form 10-K for the year ended December 31, 2015.

The financial information as of March 31, 2016, and for the three months ended March 31, 2016 and 2015, respectively, is unaudited. The financial information as of December 31, 2015 has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2015. In management’s opinion, such information contains all adjustments, consisting only of normal recurring accruals, considered necessary for a fair presentation of the results of the interim periods. The results of operations for the three months ended March 31, 2016 are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2016.

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 March 31, 2016, cash with a recorded balance totaling $14,127 and $51,565 was held at JP Morgan Chase Bank, N.A and Arvest Bank, respectively. In addition, we also held cash equivalents in the form of treasury securities with a recorded balance of $121,016 at Arvest Wealth Management. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts. We are not party to any valid blocked account agreements with respect to any material amount of cash.

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.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Accounts receivable consisted of the following at March 31, 2016 and December 31, 2015:

 

The receivable balance related to derivative settlements as of March 31, 2016, includes $382 in settlement proceeds that are being held by the counterparty for a period longer than the contractual settlement period under the derivative contract. The amount is being held as a result of the defaults under our indebtedness that has resulted in cross defaults under the master agreements governing our derivative contracts. See “Note 2–Chapter 11 filing, liquidity, going concern and derivative transactions” for a discussion of the impact of our debt defaults on our derivative master agreements.

Inventories

Inventories are comprised of equipment used in developing oil and natural gas properties and oil and natural gas product inventories. Equipment inventory is carried at the lower of cost or market using the average cost method. Oil and natural gas product inventories are stated at the lower of production cost or market. 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 at March 31, 2016 and December 31, 2015 consisted of the following:

 

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.

The costs of unevaluated oil and natural gas properties are excluded from amortization until the properties are evaluated. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Work-in-progress costs are included in unevaluated oil and natural gas properties and as of March 31, 2016, include $60,553 of capital costs incurred for undeveloped acreage and $7,205 for wells and facilities in progress pending determination. As of December 31, 2015, work-in-progress costs included capital costs incurred of $60,031 for undeveloped acreage and $6,874 for wells and facilities in progress pending determination.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

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 March 31, 2016 were prepared using an average price for oil and natural gas on the first day of each month for the prior twelve months as required by the SEC.

Due to the substantial decline of commodity prices that began in mid-2014 and which continue to remain low the cost center ceiling exceeded the net capitalized cost of our oil and natural gas properties, resulting in a ceiling test write-down during the three months ended March 31, 2016, of $77,896. Further write-downs are expected to occur if prices remain at their depressed levels. The amount of any future impairment is generally difficult to predict, and will depend on the average oil and natural gas prices during each period, the incremental proved reserves added during each period, and additional capital spent.

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.

Stock-based compensation

Our stock-based compensation programs consist of phantom stock, restricted stock units (“RSU”), and restricted stock awards issued to employees. Generally, we use new shares to grant restricted stock awards, and we cancel restricted shares forfeited or repurchased for tax withholding. Canceled shares are available to be issued as new grants under our 2010 Equity Incentive Plan. We consider the measurement of fair value of our phantom stock, RSU 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 are remeasured at the end of each reporting period until settlement. The estimated fair market value of these awards is calculated based on our total asset value less total liabilities, with assets being adjusted to fair value in accordance with the terms of the Phantom Stock Plan and the Non-Officer Restricted Stock Unit Plan. The primary adjustment required is the adjustment of oil and natural gas properties from net book value to the discounted and risk-adjusted reserve value based on internal reserve reports priced on NYMEX forward strips. Compensation cost associated with the phantom stock awards and RSU awards is recognized over the vesting period using the straight-line method and the accelerated method, respectively. The fair value of our restricted stock awards that include a service condition is 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 is remeasured at the end of each reporting period until settlement. We recognize compensation cost over the requisite service period using the accelerated method for awards with graded vesting.

We use a Monte Carlo model to estimate the grant date fair value of restricted stock awards that include a market condition. This model includes various significant assumptions, including the expected volatility of the share awards and the probabilities of certain vesting conditions. Compensation cost associated with restricted stock awards that include a market condition is recognized over the requisite service period using the straight-line method. The assumptions used to value our stock-based compensation awards reflect our best estimates, but they involve inherent uncertainties based on market conditions generally outside of our control. As a result, stock-based compensation expense could have been significantly impacted if other assumptions had been used.

The costs associated with our stock-based compensation programs is calculated net of forfeitures, which are estimated based on our historical and expected turnover rates. If our actual forfeiture rate is materially different from our estimate, the stock-based compensation cost could be different from what we have recorded in the current period.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Income Taxes

Although we recorded a net loss for the three months ended March 31, 2016, we did not record any corresponding tax benefit as any deferred tax asset arising from the loss is currently not believed to be realizable and is therefore reduced by a valuation allowance. At March 31, 2016, our valuation allowance is $511,740 which reduces our net deferred tax assets to zero value as we continue to believe that it is more likely than not that we will not realize the deferred tax assets primarily related to our cumulative net operating losses. Income tax recognized for the three months ended March 31, 2016 is a result of current Texas margin tax on gross revenues less certain deductions. See “Note 10—Income Taxes” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2015 for additional information about our income taxes.

As described in “Note 2— Chapter 11 filing, liquidity, going concern and derivative transactions”, in conjunction with our efforts to restructure our indebtedness, on May 9, 2016, we filed voluntary petitions seeking relief under Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware commencing cases for relief under Chapter 11 of the Bankruptcy Code. Our negotiations to restructure our debt include a proposal for the holders of our Senior Notes to convert those notes into equity of the reorganized Company, effectuated through a plan of reorganization in bankruptcy. Absent an exception, a debtor recognizes cancellation of indebtedness income (“CODI”) upon discharge of its outstanding indebtedness for an amount of consideration that is less than its adjusted issue price. The Internal Revenue Code of 1986, as amended (“IRC”), provides that a debtor in a Chapter 11 bankruptcy case may exclude CODI from taxable income but must reduce certain of its tax attributes by the amount of any CODI realized as a result of the consummation of a plan of reorganization. The amount of CODI realized by a taxpayer is determined based on the fair market value of the consideration received by the creditors in settlement of outstanding indebtedness. Upon emergence from Chapter 11 bankruptcy proceedings, the CODI may reduce some or all of the amount of prior tax attributes, which can include net operating losses, capital losses, alternative minimum tax credits and tax basis in assets. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year ending subsequent to the date of emergence.

The IRC provides an annual limitation with respect to the ability of a corporation to utilize its tax attributes, as well as certain built-in-losses, against future taxable income in the event of a change in ownership. Emergence from Chapter 11 bankruptcy proceedings may result in a change in ownership for purposes of the IRC. However, the IRC provides alternatives for taxpayers in Chapter 11 bankruptcy proceedings that may or may not result in an annual limitation. We are in the process of determining which alternatives are most beneficial to us in conjunction with our ongoing negotiations with our debtholders.

Liability Management

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

Cost reduction initiatives

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the depressed commodity pricing environment. The expense for the three months ended March 31, 2016 and 2015, includes $3,036 and $6,524, respectively, for one-time severance and termination benefits in connection with our reductions in force during these periods. The remaining expense is a result of third party legal and professional services we have engaged to assist in our cost savings initiatives.

Recently issued 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. The FASB recently approved a delay which will make the updated guidance effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. Early adoption is permitted only for fiscal years beginning after December 31, 2016, and interim periods thereafter. We are currently evaluating the effect the new standard will have on our financial statements and results of operations.

In July 2015, the FASB issued authoritative guidance that amends and simplifies the ways businesses value inventory so that businesses that use the first-in, first-out (FIFO) or average cost method will measure inventory at the lower of its cost or net realizable value. Net realizable value is the estimated selling price in the ordinary course of business, less reasonably predictable costs of

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

completion, disposal, and transportation. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2016 and interim periods thereafter. We do not expect this guidance to materially impact our financial statements or results of operations.

In November 2015, the FASB issued authoritative guidance aimed at simplifying the accounting for deferred taxes. Current GAAP requires the deferred taxes for each jurisdiction (or tax-paying component of a jurisdiction) to be presented as a net current asset or liability and net noncurrent asset or liability. This requires a jurisdiction-by-jurisdiction analysis based on the classification of the assets and liabilities to which the underlying temporary differences relate, or, in the case of loss or credit carryforwards, based on the period in which the attribute is expected to be realized. Any valuation allowance is then required to be allocated on a pro rata basis, by jurisdiction, between current and noncurrent deferred tax assets. To simplify presentation, the new guidance requires that all deferred tax assets and liabilities, along with any related valuation allowance, be classified as noncurrent on the balance sheet. As a result, each jurisdiction will now only have one net noncurrent deferred tax asset or liability. Importantly, the guidance does not change the existing requirement that only permits offsetting within a jurisdiction – that is, companies are still prohibited from offsetting deferred tax liabilities from one jurisdiction against deferred tax assets of another jurisdiction. The guidance is effective for public business entities in fiscal periods beginning after December 15, 2016, and interim periods thereafter. We do not expect this guidance to have a significant impact on our consolidated financial statements.

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. Early adoption of certain provisions is permitted. We are currently evaluating the effect the new guidance will have on our financial statements and results of operations.

In February 2016, the FASB issued authoritative guidance significantly amending the current accounting for leases. Under the new provisions, all lessees will report a right-of-use asset and a liability for the obligation to make payments for all leases with the exception of those leases with a term of 12 months or less. All other leases will fall into one of two categories: (i) a financing lease or (ii) an operating lease. Lessor accounting remains substantially unchanged with the exception that no leases entered into after the effective date will be classified as leveraged leases. For sale leaseback transactions, a sale will only be recognized if the criteria in the new revenue recognition standard are met. For public business entities, this guidance is effective for fiscal periods beginning after December 15, 2018 and interim periods thereafter. Early adoption is permitted. We are currently evaluating the effect the new guidance will have on our financial statements and results of operations.

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 815. The guidance is effective for fiscal years beginning after December 15, 2016. Early adoption is permitted in any interim period for which financial statements have not been issued, but would be retroactively applied to the beginning of the year that includes the interim period. We are currently evaluating the effect the new guidance will have on our financial statements and results of operations.

 

Note 2: Chapter 11 filing, going concern, liquidity and derivative transactions

Oil and natural gas prices have declined severely since mid-2014 and continue to be depressed in 2016. These lower commodity prices have negatively impacted revenues, earnings and cash flows, and sustained low oil and natural gas prices are having a material and adverse effect on our liquidity position. As a result of the adverse impact of low commodity prices on our liquidity, there is uncertainty regarding our ability to repay our outstanding debt obligations as they become due, especially in the event of any acceleration of indebtedness, and hence substantial doubt about our ability to continue as a going concern. This doubt is expressed in the audit opinion of our annual consolidated financial statements for the year ended December 31, 2015 and constitutes an event of default under our Credit Facility since the covenants under the facility require us to deliver our annual financial statements without a going concern explanatory paragraph.

On March 1 and April 1, 2016, we elected not to make interest payments on our 8.25% Senior Notes and 9.875% Senior Notes, respectively. Under the indenture governing these Senior Notes, the failure to make the interest payments was subject to a 30-day grace period before constituting an event of default. We did not make either interest payment on the Senior Notes within their respective 30-day grace periods and as a result, are currently in default under the indentures governing these Senior Notes. While in default, the outstanding principal and any accrued interest may be called and thus be immediately due and payable. Our failure to

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

make such interest payments within the 30-day grace period also resulted in a cross default under our Credit Facility, capital leases and mortgage note.

The defaults discussed above result in cross defaults on our remaining indebtedness and therefore subject all our debt to potential acceleration in the event that the outstanding amounts are called by our lenders. As a result of the defaults and potential acceleration, the annual consolidated financial statements included in our Annual Report on Form 10-K for the year ended December 31, 2015, included a reclassification of all outstanding debt to current liabilities. The reclassification to current liabilities remains in effect as of March 31, 2016. Due to this reclassification, our current liabilities exceed our current assets by a significant amount and we are therefore in violation of the current ratio covenant under our Credit Facility for the periods ending March 31, 2016 and December 31, 2015.

Faced with these defaults, we entered into agreements (the “Forbearance Agreements”) with the lenders under our Credit Facility and an ad hoc committee (the “Ad Hoc Committee”) of noteholders collectively holding more than 50% of the Senior Notes outstanding to forbear from exercising remedies on account of the missed interest payments and certain other alleged defaults specified in the Forbearance Agreements through and including May 1, 2016. While the Forbearance Agreements were in effect,we continued to engage in good-faith arm’s-length negotiations regarding a potential restructuring of the Credit Facility and the Senior Notes that would materially delever the Company’s balance sheet and allow us to retain sufficient liquidity to continue to operate our business going forward. In the course of these negotiations, the Company, the lenders under the Credit Facility, and the Ad Hoc Committee exchanged and considered, with the assistance of their respective advisors, numerous restructuring proposals. .

As part of our restructuring efforts, we are currently negotiating a Restructuring Support Agreement (the “RSA”) with certain holders of our Senior Notes. The RSA contemplates that the holders of Senior Notes (the “Senior Noteholders”) will convert their Senior Notes into equity of the reorganized Company, effectuated through a plan of reorganization in bankruptcy. The RSA also contemplates deadlines for the following bankruptcy related proceedings: (i) the filing of a plan and disclosure statement, (ii) a hearing to approve the disclosure statement and (iii) a confirmation hearing. We are also in negotiations with the agent for the lenders under the Credit Facility with respect to the treatment of their claims and certain other matters relating to a possible restructuring. At this time, no agreement has been reached regarding a restructuring of the Credit Facility or the Senior Notes, and there can be no assurances that such agreements will be reached.

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., 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”). We are currently operating our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. We will account for the bankruptcy in accordance with Accounting Standards Codification 852, Reorganizations, in the quarterly period ended June 30, 2016.

We have filed a variety of first day motions with the Bankruptcy Court that will allow us to continue to operate our business without interruption. These motions are designed primarily to minimize the impact of our bankruptcy filing on our operations, creditors and employees.

The Bankruptcy Court has granted all motions filed by us and our Chapter 11 Subsidiaries on an interim basis. As a result, we not only are able to conduct normal business activities and pay all associated obligations for the period following our bankruptcy filing, we are also authorized to pay (subject to caps applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors and funds belonging to third parties, including royalty interest holders and partners. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business require the prior approval of the Bankruptcy Court. A final hearing on the motions to satisfy our obligations to certain third parties and to forward funds held by us that belong to third parties is scheduled to be held on June 9, 2016.

Subject to certain exceptions, under the Bankruptcy Code, the filing of the bankruptcy petitions automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or the filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Creditors are stayed from taking any actions against the Debtors as a result of debt defaults, subject to certain limited exceptions permitted by the Bankruptcy Code.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

For the duration of our Chapter 11 Cases, our operations and ability to develop and execute our business plan are subject to the risks and uncertainties associated with the Chapter 11 process. As a result of these risks and uncertainties, the number of our outstanding shares of common stock and stockholders, assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in this quarterly report may not accurately reflect our operations, properties and capital plans following our emergence from bankruptcy.

In particular, subject to certain exceptions, under the Bankruptcy Code, the Debtors may assume, assign, or reject certain executory contracts and unexpired leases subject to the approval of the Bankruptcy Court and certain other conditions. Generally, the rejection of an executory contract or unexpired lease is treated as a pre-petition breach of such executory contract or unexpired lease and, subject to certain exceptions, relieves the Debtors of performing future obligations under such executory contract or unexpired lease but entitles the contract counterparty or lessor to a pre-petition general unsecured claim for damages caused by such deemed breach. Counterparties to such rejected contracts or leases may assert unsecured claims in the Bankruptcy Court against the applicable Debtors’ estate for such damages. Generally, the assumption of an executory contract or unexpired lease requires us to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description of an executory contract or unexpired lease involving us in these financial statements, including where applicable, a quantification of our obligations under any such executory contract or unexpired lease with the Debtors is qualified by our rights to reject such executory contract or unexpired lease under the Bankruptcy Code.

Our filing of the bankruptcy petitions described above constitutes an additional event of default under our Credit Facility, Senior Notes, capital leases and mortgage note.

The accompanying consolidated financial statements have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. Other than the reclassification of debt to current liabilities discussed above, the consolidated financial statements do not reflect any adjustments that might result from the outcome of the uncertainties surrounding our liquidity.

As discussed in “Note 6 – Fair value measurements” all the counterparties to our derivative transactions are also financial institutions within the lender group under our Credit Facility. Our derivative contracts with these counterparties are governed by master agreements which generally specify that a default under any of our indebtedness as well as any bankruptcy filing is an event of default which may result in early termination of the derivative contracts. As a result of our debt defaults and our bankruptcy petition, we are currently in default under our derivative agreements. In the event of an early termination of our derivative contracts as a result of a default, we may not receive the proceeds from such termination. It is possible that the counterparty financial institutions to our derivative contracts will utilize their right of offset with respect to the Credit Facility to retain such proceeds. We anticipate that many or perhaps all of our outstanding derivative contracts may be terminated in conjunction with our bankruptcy proceedings. Any potential loss of anticipated proceeds from our derivative settlements in 2016 will severely limit our cash from operations and liquidity. Furthermore, since we are in default on our indebtedness and have a bankruptcy filing, we will no longer be able to represent that we comply with the credit default or bankruptcy covenants under our derivative master agreements and thus may not be able to enter into new hedging transactions.

 

Note 3: Supplemental disclosures to the consolidated statements of cash flows

Supplemental disclosures to the consolidated statements of cash flows are presented below:

 

 

 

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Note 4: Debt

As of the dates indicated, debt consisted of the following:

 

We are currently in default on all our indebtedness. The defaults stem from, among others, our commencement of the Chapter 11 Cases, direct defaults as a result of nonpayment of interest, violations of financial covenants and the inclusion of a going concern explanatory paragraph in the audit opinion of our annual financial statements. Moreover, due to our commencement of the Chapter 11 Cases, all of our indebtedness has been accelerated by operation of law.

Senior Notes

The Senior Notes, which, as of March 31, 2016, include our 9.875% senior notes due 2020, our 8.25% senior notes due 2021 (the “2021 Senior Notes”), and our 7.625% senior notes due 2022 (collectively, our “Senior Notes”) are our senior unsecured obligations, rank equally in right of payment with all our existing and future senior debt, and rank senior to all of our existing and future subordinated debt.

As discussed in “Note 2— Chapter 11 filing, liquidity, going concern and derivative transactions,” we deferred interest payments due on our Senior Notes on March 1 and April 1, 2016, and did not make any of the payments prior to the expiration of their respective 30-day grace periods. In March 2016 we wrote off the remaining unamortized issuance costs, premium and discount related to our Senior Notes for a net charge of $16,970. These deferred items are typically amortized over the life of the corresponding bond. However, as a result of not paying the interest due on our 2021 Senior Notes by the end of our 30-day grace period on March 31, 2016, we triggered an Event of Default on our Senior Notes. While uncured, the Event of Default effectively allows the lender to demand immediate repayment, thus shortening the life of our Senior Notes to the current period. As a result, we wrote off the remaining balance of unamortized issuance costs, premium and discount as follows:

 

In accordance with accounting guidance, we will not accrue interest expense on our Senior Notes during the pendency of the Chapter 11 Cases as we do not expect to pay such interest.

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Credit Facility

In April 2010, we entered into an Eighth Restated Credit Agreement (our “Credit Facility”), which is collateralized by our oil and natural gas properties and, as amended, matures on November 1, 2017. During the three months ended March 31, 2016, we had additional net borrowings of $181,000 on our Credit Facility. As of April 1, 2016, the weighted average interest rate was 7.0% on outstanding borrowings under Credit Facility. This rate represents the default rate and is based on the Alternate Base Rate (as defined under the Credit Facility) plus an additional 2.00% and plus the applicable margin.

Availability under our Credit Facility is subject to a borrowing base which is set by the banks semiannually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. As of March 31, 2016, the borrowing base under our Credit Facility was $550,000. We are currently in negotiations with our lenders as part of our debt restructuring to determine the applicable borrowing base.

Subject to certain exceptions, under the Bankruptcy Code, the commencement of the Chapter 11 Cases automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or the filing of other actions against the Debtors or their property to recover, collect or secure a claim arising prior to the Petition Date. Creditors are stayed from taking any actions against the Debtors as a result of debt defaults, subject to certain limited exceptions permitted by the Bankruptcy Code.  There can be no assurances that the agent and lenders will consensually agree to a restructuring of the Credit Facility. Any proposed non-consensual restructuring of the Credit Facility could result in substantial delay in emergence from bankruptcy and there can be no assurances that the Bankruptcy Court would approve such proposed non-consensual restructuring. During the Chapter 11 Cases, we expect to remain current on our interest payments under the Credit Facility to the extent required by order of the Bankruptcy Court.

Capital Leases

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24,500 through the sale and subsequent leaseback of existing compressors owned by us. The carrying value of these compressors is included in our oil and natural gas full cost pool. The lease financing obligations are for 84 -month terms and include 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. Lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.8%. Minimum lease payments are approximately $3,181 annually. As discussed previously, our debt defaults and the commencement of the Chapter 11 Cases are events of default under our capital leases.

 

 

Note 5: 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, including commodity price swaps, enhanced price swaps, collars, put options, and basis protection swaps. We enter into crude oil derivative contracts to hedge a portion of our natural gas liquids production.

From time to time, we may enter into derivative contracts that are not costless but instead require payment of a premium such as purchased puts, collars and three-way collars. The cash premium can be paid at the time the contracts are initiated or deferred until the contracts settle. Payment of deferred premiums at the contract settlement date reduces the proceeds to be received upon settlement of the contracts. The fair value of our derivative contracts are reported net of any deferred premiums that are payable under the contracts.

For commodity price swaps, we 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. A three-way collar contract consists of a standard collar contract plus a sold put with a price below the floor price of the collar. The sold put option requires us to make a payment to the counterparty if the market

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price is below the sold put option price. If the market price is greater than the sold put option price, the result is the same as it would have been with a standard collar contract only. By combining the collar contract with the sold put option, we are entitled to a net payment equal to the difference between the floor price of the standard collar and the sold put option price if the market price falls below the sold put option price. This strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a traditional costless collar utilizing the value associated with the sale of a put option.

We enhance the value of certain oil swaps by combining them with sold puts or put spread contracts. Sold puts require us to make a payment to the counterparty if the market price is below the put strike price at the settlement date. If the market price is greater than the sold put price, the result is the same as it would have been with a swap contract only. A put spread is a combination of a sold put and a purchased put. If the market price falls below the purchased put option price, we will pay the spread between the sold put option price and the purchased put option price from the counterparty. The use of a sold put allows us to receive an above-market swap price while the purchased put provides a measure of downside protection. A put spread may also be constructed by entering into separate sold put and purchased put contracts.

On a purchased put option, if the market price is below the put strike price at the settlement date, we will receive a payment from the counterparty. Purchased put options are designed to provide a fixed price floor in an environment where prices have declined. In such an environment, put options may also be purchased to offset the downside from sold puts that are originally associated with enhanced swaps or collars.

We use basis protection swaps to reduce basis risk. Basis is the difference between the physical commodity being hedged and the price of the futures contract used for hedging. Basis risk is the risk that an adverse change in the futures market will not be completely offset by an equal and opposite change in the cash price of the commodity being hedged. Basis risk exists in natural gas primarily due to the geographic price differentials between cash market locations and futures contract delivery locations. Natural gas basis protection swaps are arrangements that guarantee a price differential for natural gas from a specified pricing point. We receive a payment from the counterparty if the price differential is greater than the stated terms of the contract and pay the counterparty if the price differential is less than the stated terms of the contract.

As discussed in “Note 2 – Chapter 11 filing, liquidity, going concern and derivative transactions,” certain events relating to our liquidity have impacted our compliance under the master agreements that govern our derivative transaction

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The following table summarizes our crude oil derivatives outstanding as of March 31, 2016:

 

 

 

The following tables summarize our natural gas derivative instruments outstanding as of March 31, 2016:

 

 

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Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See “Note 6 — 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.

 

 

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 non-hedge derivative gains in the consolidated statements of operations.

Non-hedge derivative gains in the consolidated statements of operations are comprised of the following:

 

 

Note 6: Fair value measurements

Fair value is defined by the 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.

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Fair value measurements 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 as follows:

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.

Recurring fair value measurements

Our financial instruments recorded at fair value on a recurring basis consist of commodity derivative contracts (see “Note 5 — Derivative instruments”). We have no Level 1 assets or liabilities as of March 31, 2016 or December 31, 2015. Our derivative contracts classified as Level 2 as of March 31, 2016 and December 31, 2015 consists of commodity price swaps and basis protection swaps, which are valued using an income approach. Future cash flows from the derivatives are estimated based on the difference between the fixed contract price and the underlying published forward market price, and are discounted at the LIBOR swap rate.

As of March 31, 2016 and December 31, 2015, our derivative contracts classified as Level 3 consisted of three-way collars, enhanced swaps, and purchased puts. 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 that of our counterparties for derivative assets.

The fair value hierarchy for our financial assets and liabilities is shown by the following table: