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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(dollars in thousands, unless otherwise noted)

 

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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(dollars in thousands, unless otherwise noted)

 

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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(dollars in thousands, unless otherwise noted)

 

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:

 

 

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(dollars in thousands, unless otherwise noted)

 

Changes in the fair value of our derivative instruments classified as Level 3 in the fair value hierarchy during the three months ended March 31, 2016 and 2015 were:

 

 

Nonrecurring fair value measurements

Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the first three months of 2016 and 2015 were escalated using an annual inflation rate of 2.42% and 2.91%, respectively, and discounted using our weighted average credit-adjusted risk-free interest rate of 20.00% and 12.40%, respectively. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See “Note 7 — Asset retirement obligations” for additional information regarding our asset retirement obligations.

Fair value of other financial instruments

Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and debt. We believe the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair values due to the short-term maturities of these instruments.

The carrying value and estimated fair value of our debt at March 31, 2016 and December 31, 2015 were as follows:

 

 

The fair value of our Senior Notes was estimated based on quoted market prices. We have not disclosed the fair value of outstanding amounts under our Credit Facility as it is not practicable to obtain a  reasonable estimate of such value while the Company is in bankruptcy and the terms of the facility are being negotiated in conjunction with its reorganization.

 

Counterparty credit risk

Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our Credit Facility at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting

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(dollars in thousands, unless otherwise noted)

 

counterparty that is a lender, or an affiliate of a lender, under our senior secured revolving credit facility can be offset against amounts owed to such counterparty lender under our senior secured revolving credit facility. As of March 31, 2016, the counterparties to our open derivative contracts consisted of seven financial institutions, of which all were subject to our rights of offset under our senior secured revolving credit facility.

The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our senior secured revolving credit facility that are available to offset our net derivative assets due from counterparties that are lenders under our senior secured revolving credit facility.

 

 

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our senior secured revolving credit facility. Payment on our derivative contracts would be accelerated in the event of a default on our senior secured revolving credit facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $727 at March 31, 2016.

 

Note 7: Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity during the three months ended March 31, 2016 and 2015.

 

 

See “Note 6 — Fair value measurements” for additional information regarding fair value assumptions associated with our asset retirement obligations.

 

 

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(dollars in thousands, unless otherwise noted)

 

Note 8: Stock-based compensation

Phantom Stock Plan and Restricted Stock Unit Plan

Effective January 1, 2004, we implemented a Phantom Unit Plan, which was revised on December 31, 2008 as the Second Amended and Restated Phantom Stock Plan (the “Phantom Plan”), to provide deferred compensation to certain key employees (the “Participants”). Under the Phantom Plan, awards vest at the end of five years, but may also vest on a pro-rata basis following a Participant’s termination of employment with us due to death, disability, retirement or termination by us without cause. Also, phantom stock will vest if a change of control event occurs. Phantom shares are cash-settled within 120 days of the vesting date.

Effective March 1, 2012, we implemented a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) to create incentives to motivate Participants to put forth maximum effort toward the success and growth of the Company and to enable us to attract and retain experienced individuals who by their position, ability and diligence are able to make important contributions to the Company’s success. The RSU Plan is intended to replace the Phantom Plan. Although the Phantom Plan remains in effect, we do not expect to make any further awards under the Phantom Plan.

Under the RSU Plan, restricted stock units may be awarded to Participants in an aggregate amount of up to 2% of the fair market value of the Company. Under the RSU Plan, awards generally vest in equal annual increments over a three -year period. RSU awards may also vest following a Participant’s termination of employment in combination with the occurrence of a change of control event, as specified in the RSU Plan. RSU awards are cash-settled, generally within 120 days of the vesting date.

A summary of our phantom stock and RSU activity during the three months ended March 31, 2016 is presented in the following table:

 

 

Due to the severe decline in commodity pricing, which has resulted in a steep decline in our estimated proved reserves, the estimated fair value per phantom share and RSU as of March 31, 2016 is $0.00. The weighted average period until all remaining phantom shares and RSUs vest is 1.1 years.

2015 Cash Incentive Plan

We adopted the Long-Term Cash Incentive Plan (the “2015 Cash LTIP”) on August 7, 2015. The 2015 Cash LTIP provides additional cash compensation to certain employees of the Company in the form of awards that generally vest in equal annual increments over a four -year period. Since the awards do not vary according to the value of the Company’s equity, the awards are not considered “stock-based compensation” under accounting guidance. We accrue for the cost of each annual increment over the period service is required to vest. We recorded compensation expense of $159 for the three months ended March 31, 2016 related to the 2015 Cash LTIP.

2010 Equity Incentive Plan

We adopted the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) on April 12, 2010. The 2010 Plan reserves a total of 86,301 shares of our class A common stock for awards issued under the 2010 Plan. All of our or our affiliates’ employees, officers, directors, and consultants, as defined in the 2010 Plan, are eligible to participate in the 2010 Plan.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

The awards granted under the 2010 Plan consist of shares that are subject to service vesting conditions (the “Time Vested” awards) and shares that are subject to market and performance vested conditions (the “Performance Vested” awards).

The Time Vested awards vest in equal annual installments over the five -year vesting period, but may also vest on an accelerated basis in the event of a transaction whereby CCMP Capital Investors II (AV-2), L.P., CCMP Energy I LTD., and CCMP Capital Investors (Cayman) II, L.P. (collectively “CCMP”) receive cash upon the sale of its class E common stock (a “Transaction” as defined in the restricted stock agreements). The Performance Vested awards vest in the event of a Transaction that achieves certain market targets as defined in the 2010 Plan. Any shares of Performance Vested awards not vested on a Separation Date (as defined in the 2010 Plan) will be forfeited as of the Separation Date.

Our 2010 Plan allows participants to elect, upon vesting of their Time Vested awards, to have us withhold shares having a fair market value greater than the minimum statutory withholding amounts for income and payroll taxes that would be due with respect to such vested shares. As a result of this provision, the Time Vested awards are classified as liability awards under accounting guidance and remeasured to fair value at the end of each reporting period. The Performance Vested awards are classified as equity awards and are not remeasured to fair value at the end of each reporting period subsequent to grant date.

We have previously modified the vesting conditions of awards granted under the 2010 Plan. Please see “Note 11—Stock-based compensation” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2015, for a discussion of the modifications.

A summary of our restricted stock activity during the three months ended March 31, 2016 is presented below:

 

 

During the three months ended March 31, 2016 and 2015, we repurchased and canceled 2,597 and 1,404 vested shares. Based on an estimated fair value of $1.00 per Time Vested restricted share, the aggregate intrinsic value of the unvested Time Vested restricted shares outstanding was $7 as of March 31, 2016.

Stock-based compensation cost

Compensation cost 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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(dollars in thousands, unless otherwise noted)

 

A portion of stock-based compensation cost associated with employees involved in our acquisition, exploration, and development activities has been capitalized as part of our oil and natural gas properties. The remaining cost is reflected in lease operating and general and administrative expenses in the consolidated statements of operations. We recognized stock-based compensation expense as follows for the periods indicated:

 

 

Our stock-based compensation expense for the three months ended March 31, 2016 and 2015 includes credits due to forfeitures resulting from our workforce reductions in January 2016 and February 2015 and lower valuations of our liability-based awards. As of March 31, 2016 and December 31, 2015, accrued payroll and benefits payable included $2 and $81, respectively, for stock-based compensation costs expected to be settled within the next twelve months. Unrecognized compensation cost is approximately $2,506 with a weighted average remaining recognition period of 1.4 years.

 

Note 9: Commitments and contingencies

Standby letters of credit (“Letters”) available under our Credit Facility are used in lieu of surety bonds with various organizations for liabilities relating to the operation of oil and natural gas properties. We had Letters outstanding totaling $828 as of March 31, 2016 and December 31, 2015. When amounts under the Letters are paid by the lenders, interest accrues on the amount paid at the same interest rate applicable to borrowings under the Credit Facility. No amounts were paid by the lenders under the Letters; therefore, we paid no interest on the Letters during the three months ended March 31, 2016 or 2015.

Litigation and Claims

Naylor Farms, Inc., individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On June 7, 2011, an alleged class action was filed against us in the United States District Court for the Western District of Oklahoma (“Naylor Farms Case”) alleging that we improperly deducted post-production costs from royalties paid to plaintiffs and other royalty interest owners as categorized in the petition from crude oil and natural gas wells located in Oklahoma. The purported class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. The plaintiffs have alleged a number of claims, including breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. We have responded to the Naylor Farms petition, denied the allegations and raised arguments and defenses. The class has not been certified, but the motion for class certification and responsive briefs were filed in the fourth quarter of 2015. The court has not ruled on the motion and no hearing has been scheduled. We are not currently able to estimate a reasonably possible loss or range of loss or what impact, if any, the Naylor Farms Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. Plaintiffs in the Naylor Farms Case have indicated, if the class is certified, they seek damages in excess of $5,000 which may increase with the passage of time, a majority of which would be comprised of interest. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

Amanda Dodson, individually and as class representative on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On May 10, 2013, Amanda Dodson, filed a complaint against us in the District Court of Mayes County, Oklahoma, (“Dodson Case”) with allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include clams for breach of contract, fraud, breach of fiduciary duty, unjust enrichment, and other claims and seek termination of leases, recovery of compensatory damages, interest, punitive damages and attorney fees on behalf of the alleged class. The alleged class includes non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We have responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the Dodson Case will have on its financial condition, results of operations or cash flows due to the preliminary status of the matters, the

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(dollars in thousands, unless otherwise noted)

 

complexity and number of legal and factual issues presented by the matter and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

Martha Donelson and John Friend, on behalf of themselves and on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On August 11, 2014, an alleged class action was filed against us, as well as several other operators in Osage County, in the United States District Court for the Northern District of Oklahoma, alleging claims on behalf of the named plaintiffs and all similarly situated Osage County land owners and surface lessees. The plaintiffs challenged leases and drilling permits approved by the Bureau of Indian Affairs without the environmental studies required under the National Environmental Protection (NEPA). Plaintiffs assert claims seeking recovery for trespass, nuisance, negligence and unjust enrichment. Relief sought includes declaring oil and natural gas leases and drilling permits obtained in Osage County without a prior NEPA study void ab initio, removing us from all properties owned by the class members, disgorgement of profits, and compensatory and punitive damages. On March 31, 2016, the Court dismissed the case against the federal agencies named as defendants, and therefore against all defendants, as an improper challenge under NEPA and the Administrative Procedures Act. On April 29, 2016, the plaintiffs filed a motion to alter or amend the court’s opinion and vacate the judgment, arguing the court does have jurisdiction to hear the claims and dismissal of the federal defendants does not require dismissal of the oil company defendants.  Plaintiffs also filed a motion to file an amended complaint to cure the deficiencies which the court found in the dismissed complaint. The Company has not yet responded to these motions, and the court has not yet ruled. As such, we are not yet able to estimate a possible loss, or range of possible loss, if any. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action and are vigorously defending the case.

Lisa West and Stormy Hopson, individually and as class representatives on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On February 18, 2016, an alleged class action was filed against us, as well as several other operators in the District Court of Pottawatomie County, State of Oklahoma (“West Case”), alleging claims on behalf of named plaintiffs and all similarly situated persons having an insurable real property interest in Cleveland, Lincoln, McClain, Okfuskee, Oklahoma, Pontotoc, Pottawatomie and Seminole Counties, Oklahoma (the “Class Area”). The plaintiffs allege the oil and gas operations conducted by us and the other defendants have induced or triggered earthquakes in the Class Area. The plaintiffs are asking the court to require the defendants to reimburse plaintiffs and class members for earthquake insurance premiums from 2011 through a future date defined as the time at which the court determines there is no longer a risk that our activities induce or trigger earthquakes, as well as attorney fees and costs and other relief. The plaintiffs have not asked for damages related to actual property damage which may have occurred. We have responded to the petition, denied the allegations and raised a number of affirmative defenses. At this time, a class has not been certified and discovery has not yet commenced. On March 18, 2016 the case was removed to the United States District Court for the Western District of Oklahoma under the Class Action Fairness Act, but plaintiffs moved to remand the matter to the Pottawatomie County court. We and other defendants have filed motions to dismiss the West Case for lack of subject matter jurisdiction, failure to state a claim upon which relief can be granted, and other grounds. We are not currently able to estimate a reasonable possible loss or range of loss or what impact, if any, the West Case will have on our financial condition, results of operations or cash flows due to the preliminary status of the matters, the complexity and number of legal and factual issues presented, and uncertainties with respect to, among other things, the nature of the claims and defenses, the potential size of the class, the scope and types of the properties and agreements involved, and the ultimate potential outcome of the matter. We dispute plaintiffs’ claims, dispute that the case meets the requirements for a class action, dispute the remedies requested are available under Oklahoma law, and are vigorously defending the case.

We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows. However, the Bankruptcy Code provides an automatic stay of the proceedings listed above, as well as other claims and actions that were or could have been brought prior to May 9, 2016.

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. Our operating leases primarily relate to CO₂ recycle compressors at our EOR facilities and office equipment while our capital leases are related to the sale and subsequent leaseback of compressors. Our purchase obligations primarily relate to contracts for the purchase of CO₂ and drilling rig services. In May 2016, we took delivery of an additional CO₂ compressor for which we have entered into an 84 month lease with monthly payments of approximately $23. Other than additional debt borrowings during the year and our new compressor lease discussed above, there were no material changes to our contractual commitments since December 31, 2015.

 

 

 

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The following discussion is intended to assist you in understanding our business and results of operations together with our present financial condition. This section should be read in conjunction with our consolidated financial statements and the accompanying notes included elsewhere in this report.

Statements in our discussion may be forward-looking statements. These forward-looking statements involve risks and uncertainties. We caution that a number of factors could cause future production, revenues and expenses to differ materially from our expectations.

Overview

Founded in 1988 and headquartered in Oklahoma City, we are a pure play Mid-Continent independent oil and natural gas exploration and production company. We have capitalized on our sustained success in the Mid-Continent area in recent years by expanding our holdings to become a leading player in the liquids-rich STACK play, which is home to multiple oil-rich reservoirs including the Oswego, Meramec, Osage and Woodford formations. In addition, we have significant holdings in the Mississippi Lime play and a leadership position in CO₂ EOR where we are now the third largest CO₂ EOR operator in the United States based on the number of active projects. This position is underscored by our activity in the North Burbank Unit in Osage County, Oklahoma, which is the single largest oil recovery unit in the state.

Our revenues, profitability and future growth depend substantially on prevailing prices for oil and natural gas and on our ability to find, develop and acquire oil and natural gas reserves that are economically recoverable. The preparation of our financial statements in conformity with generally accepted accounting principles (“GAAP”) requires us to make estimates and assumptions that affect our reported results of operations and the amount of our reported assets, liabilities and proved oil and natural gas reserves. We use the full cost method of accounting for our oil and natural gas activities.

Generally, our producing properties have declining production rates. Our December 31, 2015 reserve estimates reflect that our production rate on current proved developed producing reserve properties will decline at annual rates of approximately 18%, 15%, and 10% for the next three years. To grow our production and cash flow, we must find, develop and acquire new oil and natural gas reserves to replace those being depleted by production. Substantial capital expenditures are required to find, develop and acquire oil and natural gas reserves.

Oil and natural gas prices fluctuate widely. We generally hedge a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. The prices we receive for our oil and natural gas production affect our:

Going concern and Chapter 11 cases

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. Further, these sustained low oil and natural gas prices are having a material and adverse effect on our liquidity position. In early 2016, our forecasts indicated that i) the borrowing base under our Credit Facility would be significantly lowered and ii) we would violate certain financial covenants under our Credit Facility during the third quarter of 2016. Both these events would have potentially required us to repay all or part of the outstanding amounts on our Credit Facility and it was uncertain whether we would have sufficient liquidity to do so. As a result of the uncertainty regarding our ability to repay our outstanding debt obligations as they become due, especially in the event of any acceleration of indebtedness, there is substantial doubt about our ability to continue as a going concern. This doubt has been 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

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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 of $16.5 million and $14.8 million 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 indenture 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 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.

Since 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 potential acceleration stemming from defaults, 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 Forbearance Agreements with the lenders under our Credit Facility and the Ad Hoc Committee 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 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, Chaparral Energy, Inc. and the Chapter 11 Subsidiaries filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court commencing the Chapter 11 Cases. We are currently operating our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code.

The Bankruptcy Court has granted, on an interim basis, all motions filed by us and our Chapter 11 Subsidiaries that were designed primarily to minimize the impact of the Chapter 11 Cases on our operations, customers and employees. 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 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 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.

For the duration of the 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 described in Item 1A, “Risk Factors.” 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 conclusion of the Chapter 11 Cases and the description of our operations, properties and

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capital plans included in this quarterly report may not accurately reflect our operations, properties and capital plans following the Company’s 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 the Debtors to cure existing monetary defaults under such executory contract or unexpired lease and provide adequate assurance of future performance. Accordingly, any description in this Quarterly Report of an executory contract or unexpired lease to which we are a party, including, where applicable, a quantification of our obligations under any such executory contract or unexpired lease is qualified by our rights to reject such executory contract or unexpired lease under the Bankruptcy Code. Further, nothing herein is or shall be deemed an admission with respect to any claim amounts or calculations arising from the rejection of any executory contract or unexpired lease and we expressly preserve all of our rights with respect thereto.

Our commencement of the Chapter 11 Cases described above constitutes an additional event of default under our Senior Notes, Credit Facility, capital leases and mortgage notes.

The consolidated financial statements included in this Quarterly Report on Form 10-Q 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.

Price Uncertainty and the Full-Cost Ceiling Impairment

We deal with volatility in commodity prices primarily by maintaining flexibility in our capital investment program with a diversified drilling portfolio and limited long-term commitments, which enables us to respond quickly to industry price volatility, as well as by aggressively pursuing cost reductions in a market downturn. We also deal with price volatility by hedging a substantial portion of our expected future oil and natural gas production to reduce our exposure to commodity price decreases. Based on NYMEX forward prices at quarter end, for the remaining three quarters of 2016, we have 3.3 million barrels of crude oil production hedged at an average of $68.68 per barrel and 10,050 BBtu of natural gas production hedged at an average of $4.14/MMBtu.

Price volatility also impacts our business through the full cost ceiling test calculation. The ceiling test calculation dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date. At year-end 2015, those prices were $50.28 per Bbl for oil and $2.58 per MMBtu for natural gas, and at the end of the first quarter in 2016, they fell to $46.26 per Bbl and $2.39 per MMBtu, respectively. As a result of the decline in average prices, we recorded a ceiling test write-down of $77.9 million during the first quarter of 2016. Since the prices used in the cost ceiling are based on a trailing 12-month period, the full impact of a sudden price decline is not recognized immediately. As prices decline, the economic performance of certain properties in the reserve estimate may deteriorate to the point that they are removed from the proved reserve category, thus reducing the quantity and value of proved reserves. The use of a 12-month average will tend to spread the impact of the price change on the financial statements over several reporting periods. While the amount of any future impairment is generally difficult to predict, the average prices used in the ceiling test calculation at June 30, 2016 will most likely be lower than the preceding quarter and will result in a further write-down in the second quarter of 2016, which we expect to be in the range of $125 million to $175 million. Continued write-downs of oil and natural gas properties may occur until such time as commodity prices recover, and remain at recovered levels, so as to meaningfully increase the 12-month average price used in the ceiling test calculation. In addition to commodity prices, our production rates, levels of proved reserves, estimated future operating expenses, estimated future development costs, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Financial and Operating Highlights

Our financial and operating performance in the first quarter of 2016 includes the following highlights:

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Results of operations

Production

Production volumes by area were as follows (MBoe):

 

 

We have recently realigned the plays within our E&P Areas to better highlight those areas where we are focusing our operations and where our current and future capital will be spent. E&P Areas include the following plays: the STACK, Mississippi Lime, Panhandle Marmaton and Legacy Production Areas. Please see Items 1. and 2. Business and Properties of our Annual Report on Form 10-K for the year ended December 31, 2015 for a discussion of our plays.

Production in our E&P Areas decreased for the three months ended March 31, 2016 compared to the prior year quarter primarily due to the natural decline of our wells, the temporary shut-in of marginal wells and the overall decrease in our drilling activity due to the current low price environment. The production decline was most pronounced in our Panhandle Marmaton and Mississippi Lime plays for which we have not allocated significant drilling capital in the current year while production across our STACK play has increased as a result of our recent increased focus to drill and develop the area.

Our EOR Project Areas include both currently Active EOR Projects and Potential EOR Projects. Potential EOR Projects have no current EOR production or reserves while Active EOR Project areas include properties that have proved EOR reserves, ongoing EOR operations, or that have an approved authorization for expenditure for EOR operations. Production was flat in our Active EOR Projects for the three months ended March 31, 2016 compared to the prior year quarter as increases from our North Burbank Unit as a result of continued development and response more than offset production declines in the other units. Production decreases in our Potential EOR Projects were due to natural decline and the temporary shut-in of marginal wells due to the current pricing environment.

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Revenues

Our commodity sales are derived from the sale of oil, natural gas and natural gas liquids production. These revenues do not include the effects of derivative instruments and may vary significantly from period to period as a result of changes in volumes of production sold or changes in commodity prices.

The following table presents information about our production and commodity sales before the effects of commodity derivative settlements:

 

 

Our total commodity sales decreased significantly during the three months ended March 31, 2016 compared to the three months ended March 31, 2015 as a result of a decrease in the average price per Boe combined with a decrease in production volumes sold. Changes in our production compared to the prior year is discussed in the preceding section above while the impact of price and production volume changes on our commodity sales is disclosed in the table below.

The relative impact of changes in commodity prices and sales volumes on our oil, natural gas and natural gas liquids sales before the effects of hedging is shown in the following table:

 

 

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Derivative activities

Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. 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, costless collars, put options, and basis protection swaps.

Entering into derivative instruments allows us to predict with greater certainty the effective prices we will receive for associated oil and natural gas production. We closely monitor the fair value of our derivative contracts and may elect to settle a contract prior to its scheduled maturity date in order to lock in a gain or loss. Our derivative activities are dynamic to allow us to respond to the volatile commodity markets.

Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The following table presents information about the effects of derivative settlements on realized prices:

 

 

The estimated fair values of our oil and natural gas derivative instruments are provided below. The associated carrying values of these instruments are equal to the estimated fair values.

 

 

The effects of derivative activities on our results of operations and cash flows were as follows for the periods indicated:

 

 

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 (losses) in our consolidated statements of operations. The fluctuation in non-hedge derivative gains (losses) from period to period is due primarily to the significant volatility of oil and natural gas prices and to changes in our outstanding derivative contracts during these periods.

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Lease operating expenses

 

 

Lease operating costs are sensitive to changes in demand for field equipment, services, and qualified operational personnel, which is driven by demand for oil and natural gas. However, the timing of changes in operating costs may lag behind changes in commodity prices. Our EOR projects are more expensive to operate than traditional industry operations due to the nature of operations along with the costs of recovery and recycling of CO₂.

Lease operating expenses at both our E&P Areas and EOR Project Areas decreased on an absolute dollar basis and a per Boe basis during the three months ended March 31, 2016 compared to the three months ended March 31, 2015, primarily as a result of cost reductions from third party service providers and improved operational efficiencies which included temporary shut-in of marginal wells due to the current low price environment. Lower production volumes during the current year period also contributed to the decrease in expense.

Transportation and processing expenses

 

 

Transportation and processing expenses principally consist of expenditures to prepare and transport production from the wellhead to a specified sales point and processing costs of gas into natural gas liquids. Our transportation and processing expenses decreased during the three months ended March 31, 2016 compared to the prior year quarter as a result of an overall decrease in natural gas liquids volumes processed in conjunction with the natural decline in gas production.

Production taxes (which include ad valorem taxes)

 

 

Production taxes generally change in proportion to commodity sales. Our production taxes decreased during the three months ended March 31, 2016 compared to the three months ended March 31, 2015 primarily due to a significant reduction in revenues as a result of further declines in commodity prices in the current year coupled with production decreases. Also contributing to the decline was a lower overall effective tax rate on revenues as a result of favorable tax rates for horizontal drilling and enhanced recovery projects.

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Depreciation, depletion and amortization (“DD&A”)

 

 

We adjust our DD&A rate on oil and natural gas properties each quarter for significant changes in our estimates of oil and natural gas reserves and costs. Thus, our DD&A rate could change significantly in the future.

DD&A on oil and natural gas properties decreased for the three months ended March 31, 2016, compared to the three months ended March 31, 2015, of which $12.0 million was due to a decrease in production and $20.9 million was due to a lower rate per equivalent unit of production. Our DD&A rate per equivalent unit of production was lower as the full cost amortization base, which consists of future development costs plus the carrying value of oil and natural gas properties, is substantially lower in 2016 following $1.5 billion in ceiling-test impairments that were recorded in 2015. In contrast, reserve volumes are only marginally lower. Both factors contribute to a lower DD&A rate.

Asset impairments

 

 

The ceiling test calculation for our oil and natural gas properties dictates that we use the unweighted arithmetic average price of crude oil and natural gas as of the first day of each month for the 12-month period ending on the balance sheet date. At year-end 2015, those prices were $50.28 per Bbl for oil and $2.58 per MMBtu for natural gas, and at the end of the first quarter in 2016, they fell to $46.26 per Bbl and $2.39 per MMBtu, respectively. As a result of the decline in average prices, we recorded a ceiling test write-down of $77.9 million during the first quarter of 2016.

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General and administrative expenses (“G&A”)

 

 

Gross G&A expenses decreased during the three months ended March 31, 2016, compared to the three months ended March 31, 2015, primarily due to lower compensation and benefits costs although we also accomplished reductions across most other cost categories. Compensation and benefits were lower due to lower headcount subsequent to our workforce reduction.

Capitalized exploration and development costs decreased between periods primarily due the overall decrease in G&A as well as a lower proportion of costs subject to capitalization as we have reduced our exploration, acquisition and development activities in this low commodity price environment.

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the recent deterioration of commodity prices. We implemented workforce reductions during both the current year and prior year periods and therefore incurred $3.0 million and $6.5 million in one-time severance and termination benefits in connection with the layoffs for the three months ended March 31, 2016 and 2015, respectively. The remaining cost reduction expense is a result of third party legal and professional services we have engaged to assist in these initiatives. As discussed below in “Liquidity and capital resources,” we are allowed to exclude up to $25.0 million of expenses incurred in connection with our cost reduction initiatives, including costs related to our workforce reduction, from our EBITDA-based covenant under our Credit Facility.

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

Our G&A expenses on a Boe basis decreased for the three months ended March 31, 2016 compared to the three months ended March 31, 2015 primarily due to these same factors offset partially by the decrease in overall production volumes between periods.

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 $512 million 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 at a rate on gross revenues less certain deductions. Please 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 contains additional information about our income taxes.

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Other income and expenses

Interest expense. The following table presents interest expense for the periods indicated:

 

 

Total interest expense for the three months ended March 31, 2016 increased 11% compared to the prior year quarter primarily due to increased levels of borrowing on our Credit Facility and reduced capitalized interest. On February 11, 2016, we drew substantially all remaining availability on our Credit Facility which resulted in outstanding borrowings of $548.0 million. Capitalized interest was lower as a result of a lower carrying amount of unevaluated non-producing leasehold subsequent to the leasehold impairments we recorded in late 2014 and 2015.

Senior Note issuance costs, discount and premium. In March 2016, we wrote off the remaining unamortized issuance costs, premium and discount related to our Senior Notes for a net charge of approximately $17.0 million. 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.

Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations, debt, private equity sales and proceeds from asset dispositions. On February 11, 2016, we borrowed $141.0 million under our Credit Facility which represented substantially all the remaining undrawn amount that was available under the Credit Facility at that time. Since the Petition Date, our principal sources of liquidity have been limited to cash flow from operations and cash on hand. In addition to the cash requirements necessary to fund ongoing operations, we have incurred and continue to incur significant professional fees and other costs in connection with the preparation and administration of the Chapter 11 Cases. We anticipate that we will continue to incur significant professional fees and costs for the pendency of the Chapter 11 Cases.

Our liquidity is greatly impacted by commodity prices for which we have no control over. Beginning in mid 2014 and continuing into the present, oil, natural gas and NGL commodity prices declined significantly and are expected to fluctuate in the future. We deal with volatility in commodity prices primarily through the use of derivative contracts as part of our commodity price risk management program. However, our debt defaults and our commencement of the Chapter 11 Cases were events of default under our derivative master agreements thereby providing our derivative counterparties the right to terminate all our derivative positions. We expect that many or perhaps all of our outstanding derivative contracts may be terminated by our counterparties in the near future. As of April 30, 2016, the fair value of our derivative portfolio was a net asset of $93.6 million of which all outstanding positions are subject to potential early termination as discussed above.

As a result of our bankruptcy, we also anticipate that some or all payments of settlement proceeds from derivative transactions that matured prior to the commencement of the Chapter 11 Cases may be suspended. The anticipated suspension of payments is based on provisions in our derivative master agreements specifying that the payment and delivery obligations of a party are conditional upon, among other things, there being no Event of Default or Potential Event of Default with respect to the other party that has occurred and is continuing, and that no Early Termination Date has been designated in respect of the relevant transaction. As of April 30, 2016, we have a receivable of $25.8 million related to derivative settlement proceeds.

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All the counterparties to our derivative transactions are also financial institutions within the lender group under our Credit Facility. We expect that any suspended payments and proceeds from terminated derivatives from each counterparty will be utilized to offset the respective counterparty’s outstanding loans to us under the Credit Facility, with any excess remitted back to us.

Currently we believe it is unlikely that we will be able to enter into new derivative transactions during the pendency of the Chapter 11 Cases and there can be no assurance that after emergence from bankruptcy we will be able to enter into new derivative transactions at terms that are acceptable to us.

There are no assurances that our cash flow from operations and cash on hand will be sufficient to continue to fund our operations or to allow us to continue as a going concern until a Chapter 11 plan is confirmed by the Bankruptcy Court or another alternative restructuring transaction is approved by the Bankruptcy Court and consummated. Our long-term liquidity requirements, the adequacy of our capital resources and our ability to continue as a going concern are difficult to predict at this time and ultimately cannot be determined until a Chapter 11 plan has been confirmed, if at all, by the Bankruptcy Court. If our future sources of liquidity are insufficient, we could face substantial liquidity constraints and be unable to continue as a going concern and will likely be required to significantly reduce, delay or eliminate capital expenditures, implement further cost reductions, seek other financing alternatives or seek the sale of some or all of our assets. If we limit, defer or eliminate our 2016 capital expenditure plan or are unsuccessful in developing reserves and adding production through our capital program or our cost-cutting efforts are too overreaching, the value of our oil and natural gas properties and our financial condition and results of operations could be adversely affected.

There can be no assurances regarding our ability to successfully develop, confirm and consummate one or more plans of reorganization or other alternative restructuring transactions that satisfies the conditions of the Bankruptcy Code and, is approved by the Bankruptcy Court.

Sources and uses of cash

Our net change in cash is summarized as follows:

 

 

Our cash flows from operating activities is derived substantially from the production and sale of oil and natural gas. Our cash flows from operating activities were a deficit in both periods although marginally higher in the current quarter compared to the prior year quarter. Improved operating cash flows were the result of lower cash operating expenses, changes in working capital and a reduction of interest paid as we elected not to make a $16.5 million payment due on our Senior Notes in March 2016. These changes were partially offset by a reduction in cash from lower revenues as a result of price and production declines.

When available, we use the net cash provided by operations to partially fund our acquisition, exploration and development activities. However, as a result of the deficits discussed above, our acquisition, exploration and development activities for the three months ended March 31, 2016 and 2015, were funded primarily by settlement proceeds from our derivative instruments, borrowings from our Credit Facility and proceeds from asset dispositions.

Our cash flows from investing activities is comprised primarily of cash inflows from asset dispositions and derivative settlement receipts offset by cash outflows for capital expenditures and derivative settlement payments.

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Our actual costs incurred, including costs that we have accrued for during the three months ended March 31, 2016, and our budgeted 2016 capital expenditures for oil and natural gas properties are summarized in the table below.

 

 

 

Net cash used in investing activities during the three months ended March 31, 2016 was comprised of cash outflows for capital expenditure of $47.1 million and cash inflows from derivative settlement receipts of $47.5 million and asset dispositions of $0.5 million. Net cash used in investing activities during the three months ended March 31, 2015 was comprised primarily of cash outflows for capital expenditure of $156.8 million partially offset by derivative settlement receipts of $75.9 million and proceeds from asset dispositions of $3.1 million. Capital expenditures were significantly higher in the 2015 period as it included a significant paydown of accounts payable for expenditures accrued at the end 2014.

Cash flows from financing activities is comprised primarily of cash inflows from debt borrowings, offset by cash outflows from repayments of debt and capital leases. During the three months ended March 31, 2016, we borrowed $181.0 million on our debt and made repayments of $0.6 million on our debt and $0.6 million on our capital leases. During the three months ended March 31, 2015, we borrowed $103.0 million on our debt and made repayments of $0.9 million on our debt and $0.6 million on our capital leases.

Indebtedness

Debt consists of the following as of the dates indicated:

 

 

Substantially all of our indebtedness is currently in default as a result of: (i) our commencement of the Chapter 11 Cases, (ii) our nonpayment of interest on the Senior Notes, (iii) the going concern audit opinion in our recent annual financial statements and (iv) violation of certain financial covenants. Moreover, due to our commencement of the Chapter 11 Cases, all of our indebtedness has been accelerated by operation of law. Please see “Note 6—Debt” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2015 for a discussion of material terms governing our Senior Notes and Credit Facility.

Credit Facility

Our Credit Facility, which matures on November 1, 2017, had an outstanding balance of $548.0 million as of May 13, 2016. As a result of defaults, there is currently no availability under this facility.

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Availability under our Credit Facility is subject to a borrowing base which is set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination and in the event of early termination of our derivative contracts. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. 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.

Our Credit Facility requires us to maintain a current ratio, as defined in Credit Facility, of not less than 1.0 to 1.0. The definition of current assets and current liabilities used for determination of the current ratio computed for loan compliance purposes differs from current assets and current liabilities determined in compliance with GAAP. Since compliance with financial covenants is a material requirement under our Credit Facility, we consider the current ratio calculated under our Credit Facility to be a useful measure of our liquidity because it includes the funds available to us under our Credit Facility and is not affected by the volatility in working capital caused by changes in the fair value of derivatives. The following table discloses the current ratio for our loan compliance compared to the ratio calculated per GAAP. As discussed previously, due to the potential acceleration of our debt as a result of defaults or cross defaults on our various debt facilities, we have reclassified all long-term debt on our balance sheet to current liabilities as of March 31, 2016 and December 31, 2015. As a result, the current ratio as calculated under our Credit Facility is less than 1.0 to 1.0, which is an event of default under our Credit Facility.

 

 

Capital Leases

During 2013, we entered into lease financing agreements with U.S. Bank National Association for $24.5 million 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 payments and interest expense. As discussed previously, our debt defaults and the commencement of the Chapter 11 Cases are events of default under our capital leases.

Contractual Obligations

We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. Our operating leases primarily relate to CO₂ recycle compressors at our EOR facilities and office equipment while our capital leases are related to the sale and subsequent leaseback of compressors. Our purchase

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obligations primarily relate to contracts for the purchase of CO₂ and drilling rig services. In May 2016, we took delivery of an additional CO₂ compressor for which we have entered into an 84 month lease with monthly payments of approximately $23,000.

Other than additional debt borrowings during the year and our new compressor lease discussed above, there were no material changes to our contractual commitments since December 31, 2015.

Non-GAAP financial measure and reconciliation

Management uses adjusted EBITDA as a supplemental financial measurement to evaluate our operational trends. Items excluded generally represent non-cash adjustments, the timing and amount of which cannot be reasonably estimated and are not considered by management when measuring our overall operating performance. In addition, adjusted EBITDA is generally consistent with the Consolidated EBITDAX calculation that is used in the covenant ratio required under our Credit Facility described in the Liquidity and Capital Resources section of Management’s Discussion and Analysis of Financial Condition and Results of Operations. We consider compliance with this covenant to be material. Adjusted EBITDA is used as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to net income, as an indicator of our operating performance, as an alternative to cash flows from operating activities, or as a measure of liquidity. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.

We define adjusted EBITDA as net income, adjusted to exclude (1) asset impairments, (2) interest and other financing costs, net of capitalized interest, (3) income taxes, (4) depreciation, depletion and amortization, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, (9) upfront premiums paid on settled derivative contracts, (10) impairment charges, and (11) expenses associated with our cost reduction initiatives, transition, business optimization and other restructuring charges not to exceed $25.0 million on a cumulative basis and (12) other significant, unusual non-cash charges.

The following table provides a reconciliation of our net income (loss) to adjusted EBITDA for the specified periods:

 

 

Critical accounting policies

For a discussion of our critical accounting policies, which remain unchanged, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations ” in our Annual Report on Form 10-K for the year ended December 31, 2015.

Also see the footnote disclosures included in “Note 1 — Nature of operations and summary of significant accounting policies” in Item 1. Financial Statements of this report.

Recent accounting pronouncements

See recently adopted and issued accounting standards in “Note 1 — Nature of operations and summary of significant accounting policies ” in Item 1. Financial Statements of this report.

 

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Commodity prices. Our financial condition, results of operations and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil and natural gas. These commodity prices are subject to wide fluctuations and market uncertainties due to a variety of factors that are beyond our control. We cannot predict future oil and natural gas prices with any degree of certainty. Sustained declines in oil and natural gas prices may adversely affect our financial condition and results of operations, and may also reduce the amount of net oil and natural gas reserves that we can produce economically. Any reduction in reserves, including reductions due to price fluctuations, can reduce our borrowing base under our Credit Facility and adversely affect our liquidity and our ability to obtain capital for our acquisition, exploration and development activities. Based on our production for the three months ended March 31, 2016, our gross revenues from oil and natural gas sales would change approximately $1.6 million for each $1.00 change in oil and natural gas liquid prices and $0.4 million for each $0.10 change in natural gas prices.

To mitigate a portion of our exposure to fluctuations in commodity prices, we enter into various types of derivative instruments, including commodity price swaps, costless collars, put options, and basis protection swaps. We currently 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. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Please see “Note 5 — Derivative instruments” in Item 1. Financial statements of this report for further discussion of our derivative instruments.

Derivative positions are adjusted in response to changes in prices and market conditions as part of an ongoing dynamic process. We review our derivative positions continuously and if future market conditions change, we may execute a cash settlement with our counterparty, restructure the position, or enter into a new swap that effectively reverses the current position (a counter-swap). The factors we consider in closing or restructuring a position before the settlement date are identical to those we reviewed when deciding to enter into the original derivative position.

Our outstanding crude oil derivative instruments as of March 31, 2016 are summarized below:

 

 

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Our outstanding natural gas derivative instruments as of March 31, 2016 are summarized below:

 

 

Our debt defaults and the commencement of our Chapter 11 Cases were events of default under our derivative master agreements thereby providing our derivative counterparties the right to terminate all our derivative positions. Please see “Liquidity and capital resources” in Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations for a discussion on the impact of our master agreement defaults on our derivative portfolio and our ability to hedge.

Interest rates. All of the outstanding borrowings under our Credit Facility as of March 31, 2016 are subject to market rates of interest as determined from time to time by the banks. As of April 1, 2016, borrowings bear interest at a default rate which is based on the Alternate Base Rate, as defined under the Credit Facility, plus a margin that varies depending on our utilization percentage, and plus an additional 2.00%. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level of $550.0 million, equal to our borrowing base at March 31, 2016, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $5.5 million.

 

 

Disclosure controls and procedures

We have established disclosure controls and procedures to ensure that material information relating to us, including our consolidated subsidiaries, is made known to the officers who certify our financial reports and to other members of senior management and the board of directors. Based on their evaluation as of the end of the period covered by this quarterly report, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that the information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms and are effective to ensure that information required to be disclosed in such reports is accumulated and

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communicated to our management, including our principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Internal control over financial reporting

There were no changes in our internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We may make changes in our internal control procedures from time to time.

 

 

PART II—OTHER INFORMATION

Please see “Note 9 — Commitments and contingencies” in Item 1. Financial Statements of this report for a discussion of our material legal proceedings. In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

We are subject to the risks and uncertainties associated with Chapter 11 Cases.

For the duration of our Chapter 11 Cases, our operations and our ability to develop and execute our business plan, and our continuation as a going concern, are subject to the risks and uncertainties associated with bankruptcy. These risks include the following:

 

These risks and uncertainties could affect our business and operations in various ways. For example, negative events associated with our Chapter 11 Cases could adversely affect our relationships with our suppliers, service providers, customers, employees, and other third parties, which in turn could adversely affect our operations and financial condition. Also, we need the prior approval of the Bankruptcy Court for transactions outside the ordinary course of business, which may limit our ability to respond timely to certain events or take advantage of certain opportunities. Because of the risks and uncertainties associated with our Chapter 11 Cases, we cannot accurately predict or quantify the ultimate impact that events that occur during our Chapter 11 Cases will have on our business, financial condition and results of operations.

We believe it is highly likely that the shares of our existing common stock will be cancelled in our Chapter 11 Cases.

We have a significant amount of indebtedness that is senior to our existing common stock in our capital structure. As a result, we believe that it is highly likely that the shares of our existing common stock will be cancelled in our Chapter 11 Cases and investors will receive little to no recovery on account of such shares.

Operating under Bankruptcy Court protection for a long period of time may harm our business.  

Our future results are dependent upon the successful confirmation and implementation of a plan of reorganization. A long period of operations under Bankruptcy Court protection could have a material adverse effect on our business, financial condition,

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results of operations and liquidity. So long as the proceedings related to the Chapter 11 Cases continue, our senior management will be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing exclusively on our business operations. A prolonged period of operating under Bankruptcy Court protection also may make it more difficult to retain management and other key personnel necessary to the success and growth of our business. In addition, the longer the proceedings related to the Chapter 11 Cases continue, the more likely it is that our customers and suppliers will lose confidence in our ability to reorganize our businesses successfully and will seek to establish alternative commercial relationships.

Furthermore, so long as the proceedings related to the Chapter 11 Cases continue, we will be required to incur substantial costs for professional fees and other expenses associated with the administration of the Chapter 11 proceeding. The Chapter 11 proceedings may also require us to seek debtor-in-possession financing to fund operations. If we are unable to obtain such financing on favorable terms or at all, our chances of successfully reorganizing our business may be seriously jeopardized, the likelihood that we instead will be required to liquidate our assets may be enhanced, and, as a result, any securities in the Debtor could become further devalued or become worthless.

Furthermore, we cannot predict the ultimate amount of all settlement terms for the liabilities that will be subject to a plan of reorganization. Even once a plan of reorganization is approved and implemented, our operating results may be adversely affected by the possible reluctance of prospective lenders and other counterparties to do business with a company that recently emerged from Chapter 11 proceedings.

We may not be able to obtain confirmation of a Chapter 11 Plan of Reorganization.  

To emerge successfully from Bankruptcy Court protection as a viable entity, we must meet certain statutory requirements with respect to adequacy of disclosure with respect to a Chapter 11 plan of reorganization (“Plan”), solicit and obtain the requisite acceptances of such a plan and fulfill other statutory conditions for confirmation of such a plan, which have not occurred to date. The confirmation process is subject to numerous, unanticipated potential delays, including a delay in the Bankruptcy Court’s commencement of the confirmation hearing regarding our plan.

We may not receive the requisite acceptances of constituencies in the proceedings related to the Chapter 11 proceedings to confirm our Plan. Even if the requisite acceptances of our Plan are received, the Bankruptcy Court may not confirm such a plan. The precise requirements and evidentiary showing for confirming a plan, notwithstanding its rejection by one or more impaired classes of claims or equity interests, depends upon a number of factors including, without limitation, the status and seniority of the claims or equity interests in the rejecting class (i.e., secured claims or unsecured claims, subordinated or senior claims, preferred or common stock).

If a Chapter 11 plan of reorganization is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if anything, holders of claims against us would ultimately receive with respect to their claims.

Even if a Chapter 11 Plan of Reorganization is consummated, we will continue to face risks.

Even if a Chapter 11 plan of reorganization is consummated, we will continue to face a number of risks, including certain risks that are beyond our control, such as further deterioration or other changes in economic conditions, changes in our industry, potential revaluing of our assets due to Chapter 11 proceedings, changes in consumer demand for, and acceptance of, our oil and gas and increasing expenses. Some of these concerns and effects typically become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, there is no guaranty that a confirmed Chapter 11 plan of reorganization will achieve our stated goals.

In addition, at the outset of the Chapter 11 proceedings, the Bankruptcy Code gives the Debtor the exclusive right to propose the Plan and prohibits creditors, equity security holders and others from proposing a plan. We have currently retained the exclusive right to propose the Plan. If the Bankruptcy Court terminates that right, however, or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of the Plan in order to achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through the Plan, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the proceedings related to the Chapter 11 Cases. Adequate funds may not be available when needed or may not be available on favorable terms.

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We have substantial liquidity needs and may be required to seek additional financing. If we are unable to obtain financing on satisfactory terms or maintain adequate liquidity, our ability to replace our proved reserves or to maintain current production levels and generate revenue will be limited.

Our principal sources of liquidity historically have been cash flow from operations, sales of oil and natural gas properties, borrowings under our Credit Facility, and issuances of debt securities. Our capital program will require additional financing above the level of cash generated by our operations to fund growth. If our cash flow from operations remains depressed or decreases as a result of lower commodity prices or otherwise, our ability to expend the capital necessary to replace our proved reserves, maintain our leasehold acreage or maintain current production may be limited, resulting in decreased production and proved reserves over time. In addition, drilling activity may be directed by our partners in certain areas and we may have to forfeit acreage if we do not have sufficient capital resources to fund our portion of expenses.

We face uncertainty regarding the adequacy of our liquidity and capital resources and have extremely limited, if any, access to additional financing. In addition to the cash requirement necessary to fund ongoing operations, we have incurred significant professional fees and other costs in connection with preparation for the Chapter 11 proceedings and expect that we will continue to incur significant professional fees and costs throughout our Chapter 11 proceedings. We cannot assure you that cash on hand and cash flow from operations will be sufficient to continue to fund our operations and allow us to satisfy our obligations related to Chapter 11 Cases until we are able to emerge from our Chapter 11 proceedings.

Our liquidity, including our ability to meet our ongoing operational obligations, is dependent upon, among other things; (i) our ability to comply with the terms and conditions of any cash collateral order entered by the Bankruptcy Court in connection with the Chapter 11 proceedings, (ii) our ability to maintain adequate cash on hand, (iii) our ability to generate cash flow from operations, (iv) our ability to develop, confirm and consummate a Chapter 11 plan or other alternative restructuring transaction, and (v) the cost, duration and outcome of the Chapter 11 proceedings. Our ability to maintain adequate liquidity depends in part upon industry conditions and general economic, financial, competitive, regulatory and other factors beyond our control. In the event that cash on hand and cash flow from operation is not sufficient to meet our liquidity needs, we may be required to seek additional financing. We can provide no assurance that additional financing would be available or, if available, offered to us on acceptable terms. Our access to additional financing is, and for the foreseeable future will likely continue to be, extremely limited if it is available at all. Our long-term liquidity requirements and the adequacy of our capital resources are difficult to predict at this time.

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

If the Bankruptcy Court finds that it would be in the best interest of creditors and/or the Company, the Bankruptcy Court may convert our Chapter 11 bankruptcy case to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate the Debtors’ assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under Chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in a Chapter 11 plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a disorderly fashion over a short period of time rather than reorganizing or selling in a controlled manner the Company’s businesses as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with cessation of operations.

We may be subject to claims that will not be discharged in the Chapter 11 proceedings, which could have a material adverse effect on our financial condition and results or operations.

The Bankruptcy Code provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to May 10, 2016 or before confirmation of the plan of reorganization (i) would be subject to compromise and/or treatment under the plan of reorganization and/or (ii) would be discharged in accordance with the terms of the plan of reorganization. Any claims not ultimately discharged through a plan of reorganization could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

Our financial results may be volatile and may not reflect historical trends.

During the Chapter 11 proceedings, we expect our financial results to continue to be volatile as asset impairments, asset dispositions, restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the bankruptcy filing.

In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans

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pursuant to a plan of reorganization. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

Transfers of our equity, or issuances of equity in connection with our Chapter 11 proceedings, may impair our ability to utilize our federal income tax net operating loss carryforwards in future years.

Under federal income tax law, a corporation is generally permitted to deduct from taxable income net operating losses carried forward from prior years. We have federal net operating loss carryforwards of approximately $441 million as of December 31, 2015. Our ability to utilize our net operating loss carryforwards to offset future taxable income and to reduce federal income tax liability is subject to certain requirements and restrictions. If we experience an “ownership change,” as defined in section 382 of the Internal Revenue Code, then our ability to use our net operating loss carryforwards may be substantially limited, which could have a negative impact on our financial position and results of operations. Generally, there is an “ownership change” if one or more stockholders owning 5% or more of a corporation’s common stock have aggregate increases in their ownership of such stock of more than 50 percentage points over the prior three-year period. Following the implementation a plan of reorganization, it is possible that an “ownership change” may be deemed to occur. Under section 382 of the Internal Revenue Code, absent an applicable exception, if a corporation undergoes an “ownership change,” the amount of its net operating losses that may be utilized to offset future taxable income generally is subject to an annual limitation.

 

Please see “Note 2—Chapter 11 filing, liquidity, going concern and derivative transactions” in Item 1. Financial Statements of this report for a discussion of our default upon senior securities.

 

None.

 

 

 

 

 

 

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

 

 

Date: May 16, 2016

 

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EXHIBIT INDEX

 

 

 

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