UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

For the quarterly period ended March 31, 2017

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  ☐    No  ☒

(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  ☒    No  ☐

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

 

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) 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  ☐    No  ☒

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.                  Yes  ☒    No  ☐

Number of shares outstanding of each of the issuer’s classes of common stock as of May 15, 2017:

 

 

 

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CHAPARRAL ENERGY, INC.

Index to Form 10-Q

 

 

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CAUTIONARY NOTE

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. In addition to the risk 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, 2016, the factors 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.

 

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GLOSSARY OF CERTAIN DEFINED 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

(Unaudited)

 

 

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

 

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Chaparral Energy, Inc. and subsidiaries

Consolidated statements of stockholders’ equity (deficit)

 

 

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

(Unaudited)

 

 

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. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to March 21, 2017, and to the pre-emergence company as “Predecessor” for periods prior to March 21, 2017. As discussed in “Note 2—Chapter 11 Reorganization,” we filed voluntary petitions for bankruptcy relief and subsequently operated as debtor in possession, in accordance with the applicable provisions of the Bankruptcy Code, until our emergence from bankruptcy on March 21, 2017. The cancellation of all existing shares outstanding followed by the issuance of new shares in the reorganized Company upon our emergence from bankruptcy caused a related change of control under US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Reorganization Plan, the Company’s consolidated financial statements on or after March 21, 2017, are not comparable with the consolidated financial statements prior to that date.

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, 2016.

The financial information as of March 31, 2017, and for the periods of March 22, 2017, through March 31, 2017 (Successor), and January 1, 2017, through March 21, 2017 (Predecessor), and the three months ended March 31, 2016, is unaudited. The financial information as of December 31, 2016, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2016. In management’s opinion, such information contains all adjustments considered necessary for a fair presentation of the results of the interim periods. The results of operations for the periods of March 22, 2017, through March 31, 2017 (Successor), and January 1, 2017, through March 21, 2017 (Predecessor), are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2017.

Cash and 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, 2017, cash with a recorded balance totaling approximately $27,600 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts.

As of March 31, 2017 we had restricted cash of $14,200 which is included in “Cash and cash equivalents” in our consolidated balance sheets. The restricted funds were maintained primarily to pay debtor related professional fees associated with our reorganization as well as certain convenience class unsecured claims upon our emergence from bankruptcy. As of December 31, 2016, we had restricted cash of $1,400 which was required to be maintained during the pendency of our bankruptcy.

Accounts receivable

We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. Accounts receivable consisted of the following at March 31, 2017, and December 31, 2016:

 

 

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Chaparral Energy, Inc. and subsidiaries

 

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Inventories

Inventories consisted of the following at March 31, 2017, and December 31, 2016:

 

 

Oil and natural gas properties

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

In the past, the costs associated with unevaluated properties typically relate to acquisition costs of unproved acreage. However, as a result of fresh start accounting, substantially all of the carrying value of our unevaluated properties are the result of a fair value increase to reflect the value of our acreage in our STACK play (see “Note 3—Fresh start accounting”).

The costs of unevaluated oil and natural gas properties consisted of the following at March 31, 2017, and December 31, 2016:

 

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, 2017, 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. As discussed in “Note 3—Fresh start accounting,” our application of fresh start accounting to our balance sheet on March 21, 2017,  resulted in the carrying value of our oil and natural gas properties being restated based on their fair value. The estimated fresh start fair value along with adjustments for activity between March 21, 2017, and the end of the first quarter of 2017 as well as the increase in SEC average prices resulted in a carrying value that was below the full cost ceiling at quarter-end and thus a ceiling test write-down was not required.

Income taxes

We recorded income tax expense during the Successor and Predecessor periods in 2017 to reflect our obligation for current Texas margin tax on gross revenues less certain deductions. We did not record any net deferred tax benefit in the Successor or Predecessor periods in 2017 as any deferred tax asset arising from the benefit is reduced by a valuation allowance.

A valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding our future taxable income, as well as the jurisdiction in which such taxable income is generated, to determine whether a

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Chaparral Energy, Inc. and subsidiaries

 

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

valuation allowance is required. Such evidence can include our current financial position, our results of operations, both actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business economics of our industry.

As of the bankruptcy emergence date of March 21, 2017, we are in a net deferred tax asset position and based on our anticipated operating results in subsequent quarters, we project being in a net deferred tax asset position at December 31, 2017. We believe it is more likely than not that these deferred tax assets will not be realized, and accordingly, recorded a full valuation allowance against our net deferred tax assets as of March 21, 2017, and as of March 31, 2017.

We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can determine that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not that its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings,  improvements in oil prices, and taxable events that could result from one or more transactions. The valuation allowance does not prevent future utilization of the tax attributes if we recognize taxable income. As long as we conclude that the valuation allowance against its net deferred tax assets is necessary, we likely will not have any additional deferred income tax expense or benefit.

The benefit of an uncertain tax position taken or expected to be taken on an income tax return is recognized in the consolidated financial statements at the largest amount that is more likely than not to be sustained upon examination by the relevant taxing authority. Interest and penalties, if any, related to uncertain tax positions would be recorded in interest expense and other expense, respectively. There were no uncertain tax positions at March 31, 2017, and December 31, 2016.

As described in “Note 2—Chapter 11 Reorganization,” elements of the Reorganization Plan provided that our indebtedness related to Senior Notes and certain general unsecured claims were exchanged Successor common stock in settlement of those claims. 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. As a result of the market value of equity upon emergence from Chapter 11 bankruptcy proceedings, the estimated amount of CODI is approximately $61,000, which will reduce the value of the Company’s net operating losses. The actual reduction in tax attributes does not occur until the first day of the Company’s tax year subsequent to the date of emergence, or January 1, 2018. The reduction of net operating losses is expected to be fully offset by a corresponding decrease in valuation allowance.

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 resulted in a change in ownership for purposes of the IRC Section 382. We analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the ownership change and cancellation of indebtedness income on its tax attributes. Upon filing its 2017 U.S. Federal income tax return, we plan to elect an available alternative which would likely result in the Company experiencing a limitation that subjects existing tax attributes at emergence to an IRC Section 382 limitation that could result in some or all of the remaining net operating loss carryforwards expiring unused. However, we will continue to evaluate the remaining available alternatives which would not subject existing tax attributes to an IRC Section 382 limitation.

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 petition. As a result of our Chapter 11 petition, such expenses, to the extent that they are incremental and directly related to our bankruptcy reorganization, are reflected in “Reorganization items” in our consolidated statements of operations.

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Chaparral Energy, Inc. and subsidiaries

 

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Cost reduction initiatives

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the depressed commodity pricing environment. The expense consists of costs for one-time severance and termination benefits in connection with our reductions in force and third party legal and professional services we have engaged to assist in our cost savings initiatives as follows:

 

 

Recently adopted accounting pronouncements

In March 2016, the FASB issued authoritative guidance with the objective to simplify several aspects of the accounting for share-based payments, including accounting for income taxes when awards vest or are settled, statutory withholdings and accounting for forfeitures. Classification of these aspects on the statement of cash flows is also addressed. We have adopted this guidance, which was effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter, in the current quarter, with no material impact to our financial statements of results of operation. We did not have any previously unrecognized excess tax benefits that required an adjustment to the opening balance of retained earnings under the modified retrospective transition method required by the guidance.

In March 2016, the FASB issued authoritative guidance that clarifies that the assessment of whether an embedded contingent put or call option in a financial instrument is clearly and closely related to the debt host requires only an analysis of the four-step decision sequence described in ASC 815. We adopted this guidance, which was effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter, in the current quarter, with no material impact to our financial statements or results of operations.

In August 2014, the FASB issued authoritative guidance that required entities to evaluate whether there is substantial doubt about their ability to continue as a going concern and required additional disclosures if certain criteria were met. The guidance was adopted on December 31, 2016, and other than discussions regarding our emergence from bankruptcy and the related exit financing in “Note 2 — Chapter 11 reorganization” and “Note 6—Debt”, there were no additional required disclosures as contemplated by this guidance.

Recently issued accounting pronouncements

In January 2017, the FASB issued authoritative guidance that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described under updated revenue recognition guidance. The guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. For all other entities, it is effective for fiscal years beginning after December 15, 2018, and interim periods within fiscal years beginning after December 15, 2019. Early adoption is permitted. We expect that adoption of the new guidance may reduce the likelihood that a future transaction would be accounted for as a business combination although such a determination may require a greater degree of judgment.

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 updated guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period. The new standard allows for either full retrospective adoption, meaning the standard is applied to all periods presented in the financial statements, or modified retrospective adoption, meaning the standard is applied only to the most current period presented. During 2015 and 2016, the FASB released further updates that, among others, provided supplemental guidance and clarification to this topic including clarification on

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Chaparral Energy, Inc. and subsidiaries

 

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

principal vs. agent considerations and identifying performance obligations and licensing. We are currently evaluating the effect the new standard and its subsequent updates will have on our financial statements and results of operations. In 2017, we established an implementation team and engaged external advisers to develop a multi-phase plan to assess our business and contracts, as well as any changes to processes to adopt the requirements of the new standard and its related updates.

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 do not expect this guidance to materially impact our financial statements or 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. Furthermore, all 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, and should be applied using a modified retrospective approach. Early adoption is permitted. Based on an assessment of our current operating leases, which are predominantly comprised of leases for CO₂ compressors, we do not expect this guidance to materially impact our balance sheet or results of operations. However, we also enter into contractual arrangements relating to rights of ways or surface use that are typical of upstream oil and gas operations. We are currently assessing whether such arrangements are included in the new guidance and the potential impact, if any, on our financial statements or results of operations from these arrangements.

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

In August 2016, the FASB issued authoritative guidance which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable. Early adoption is permitted. We do not expect this guidance to have a material impact on our consolidated statement of cash flows.

 

Note 2: Chapter 11 reorganization

Bankruptcy petition and emergence. On May 9, 2016 (the “Petition Date”), Chaparral Energy, Inc. and its subsidiaries including Chaparral Energy, L.L.C., Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO₂ , L.L.C., CEI Pipeline, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., Roadrunner Drilling, L.L.C. (collectively, the “Chapter 11 Subsidiaries” and, together with Chaparral Energy, Inc., the “Debtors”) filed voluntary petitions seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) commencing cases for relief under chapter 11 of the Bankruptcy Code (the “Chapter 11 Cases”).

On March 10, 2017 (the “Confirmation Date”), the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017 (the “Effective Date”), the Reorganization Plan became effective and we emerged from bankruptcy.

Debtor-In-Possession.  During the pendency of the Chapter 11 Cases, we operated our business as debtors-in-possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by us which were designed primarily to minimize the impact of the Chapter 11 Cases on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, amounts due to taxing authorities for production and other related taxes and funds belonging

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Chaparral Energy, Inc. and subsidiaries

 

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

to third parties, including royalty and working interest holders. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business required the approval of the Bankruptcy Court.

Automatic Stay. 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 us or our property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order from the Bankruptcy Court, substantially all of our pre-petition liabilities were subject to settlement under the Bankruptcy Code.

Plan of Reorganization. Pursuant to the terms of the Reorganization Plan, which was supported by us, certain lenders under our Prior Credit Facility (collectively, the “Lenders”) and certain holders of our Senior Notes (collectively, the “Noteholders”), the following transactions occurred on or around the Effective Date:

In support of the Reorganization Plan, the Company estimated the enterprise value of the Successor to be in the range of $1,050,000 to $1,350,000, which was subsequently approved by the Bankruptcy Court. In accordance with the Reorganization Plan,

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Chaparral Energy, Inc. and subsidiaries

 

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

our post-emergence board of directors is made up of seven directors consisting of the Chief Executive Officer of the post-emergence Company (K. Earl Reynolds) and six non-employee members. Our new board members are Mr. Robert Heineman (Chairman of the Board), Mr. Douglas Brooks, Mr. Kenneth Moore, Mr. Matthew Cabell, Mr. Samuel Langford and Mr. Gysle Shellum.

Liabilities Subject to Compromise. In accordance with ASC 852 “Reorganizations,” our financial statements include amounts classified as liabilities subject to compromise which represent estimates of pre-petition obligations that were allowed as claims in our bankruptcy case. These liabilities are reported at the amounts allowed by the Bankruptcy Court, even if they may be settled for lesser amounts. The amounts disclosed below as of March 21, 2017, reflect the liabilities immediately prior to our Reorganization Plan becoming effective:

 

Note 3: Fresh start accounting

Upon emergence from bankruptcy, we qualified for and applied fresh start accounting to our financial statements in accordance with the provisions set forth in ASC 852 as (i) the holders of existing voting shares of the Company prior to its emergence received less than 50% of the voting shares of the Company outstanding following its emergence from bankruptcy and (ii) the reorganization value of our assets immediately prior to confirmation of the Reorganization Plan was less than the post-petition liabilities and allowed claims.

Adopting fresh start accounting results in a new reporting entity for financial reporting purposes with no beginning retained earnings or deficit. The cancellation of all existing shares outstanding on the Effective Date and issuance of new shares in the reorganized Company caused a related change of control under US GAAP. As a result of the application of fresh start accounting, as well as the effects of the implementation of the Reorganization Plan, the Predecessor and Successor periods may lack comparability, as required in Accounting Standards Codification Topic 205, Presentation of Financial Statements (“ASC 205”). ASC 205 states financial statements are required to be presented comparably from year to year, with any exceptions to comparability clearly disclosed. Therefore, "black-line" financial statements are presented to distinguish between the Predecessor and Successor periods.

Enterprise Value and Reorganization Value

Reorganization value represents the fair value of the Company's total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the Company's assets immediately after restructuring. The reorganization value was allocated to the Company's individual assets based on their estimated fair values.

The Company's reorganization value was derived from enterprise value. Enterprise value represents the estimated fair value of an entity's long-term debt and equity. The enterprise value of the Company on the Effective Date, as approved by the Bankruptcy Court in support of the Plan, was estimated to be within a range of $1,050,000 to $1,350,000 with a mid-point value of $1,200,000. Based upon the various estimates and assumptions necessary for fresh start accounting, as further discussed below, the estimated enterprise value was determined to be $1,200,000 before consideration of cash and cash equivalents and outstanding debt at the Effective Date.

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Chaparral Energy, Inc. and subsidiaries

 

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

The following table reconciles the enterprise value to the estimated fair value of the Successor’s common stock as of the Effective Date:

____________________________________________________________

The following table reconciles the enterprise value to the estimated reorganization value of the Successor’s assets as of the Effective Date:

 

Valuation of Oil and Gas Properties

The Company’s principal assets are its oil and gas properties, which are accounted for under the full cost method of accounting. The oil and gas properties include proved reserves and unevaluated leasehold acreage. With the assistance of valuation consultants, the Company estimated the fair value of its oil and gas properties based on the discounted cash flows expected to be generated from these assets. The computations were based on market conditions and reserves in place as of the Effective Date.

The fair value analysis was based on the Company’s estimates of proved, probable and possible reserves developed internally by the Company’s reservoir engineers. Discounted cash flow models were prepared using the estimated future revenues and development and operating costs for all developed wells and undeveloped locations comprising the proved, probable and possible reserves. The value estimated for probable and possible reserves was utilized as an estimate of the fair value of the Company’s unevaluated leasehold acreage, which was further corroborated against comparable market transactions. Future revenues were based upon the forward NYMEX strip for oil and natural gas prices as of the Effective Date, adjusted for differentials realized by the Company. Development and operating cost estimates for the oil and gas properties were adjusted for inflation. The after-tax cash flows were discounted to the Effective Date at discount rate of 8.5%. This discount rate was derived from a weighted average cost of capital computation which utilized a blended expected cost of debt and expected return on equity for similar industry participants. Risk adjustment factors were applied to the values derived for the proved non-producing, proved undeveloped, probable and possible reserve categories based on consideration of the risks associated with geology, drilling success rates, development costs and the timing of development and extraction. The discounted cash flow models also included depletion, depreciation and income tax expense associated with an after-tax valuation analysis.

From this analysis the Company estimated the fair value of its proved reserves and undeveloped leasehold acreage to be $604,065 and $585,574, respectively, as of the Effective Date. These amounts are reflected in the Fresh Start Adjustments item (i) below.

Other valuations

Our adoption of fresh start accounting also required adjustments to certain other assets and liabilities on our balance sheet including property and equipment, other assets and asset retirement obligations.

Property and equipment — consists of real property which includes our headquarters, field offices and pasture land, and personal property which includes vehicles, machinery and equipment, office equipment and fixtures and a natural gas pipeline. These assets were valued using a combination of cost, income and market approaches with the exception of pasture land where we relied on government data to determine fair value.

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Chaparral Energy, Inc. and subsidiaries

 

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Other assets — includes, among others, an equity investment in a company that operates ethanol plants. The equity investment was valued utilizing a combination of the market approaches such as the guideline public company method and the similar transactions method.

Asset retirement obligations — our fresh start updates to these obligations included application of the Successor’s credit adjusted risk free rate, which now incorporates a term structure based on the estimated timing of plugging activity, and resetting all obligations to a single layer.

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Chaparral Energy, Inc. and subsidiaries

 

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Consolidated Balance Sheet

The following consolidated balance sheet is as of March 21, 2017. This consolidated balance sheet includes adjustments that reflect the consummation of the transactions contemplated by the Reorganization Plan (reflected in the column "Reorganization Adjustments") as well as fair value adjustments as a result of the adoption of fresh start accounting (reflected in the column "Fresh Start Adjustments") as of the Effective Date:

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Reorganization adjustments

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Fresh start adjustments

Reorganization Items

We use this category to reflect, where applicable, post-petition revenues, expenses, gains and losses that are direct and incremental as a result of the reorganization of the business. Reorganization items are as follows:

 

 

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Note 4: Supplemental disclosures to the consolidated statements of cash flows

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

 

 

Note 5: Debt

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

 

Prior to our emergence from bankruptcy, our debt consisted of the Prior Credit Facility and our Senior Notes. On the Effective Date, our obligations under the Senior Notes, including principal and accrued interest, were fully extinguished in exchange for equity in the Successor. In addition, our Prior Credit Facility, previously consisting of a senior secured revolving credit facility, was restructured into the New Credit Facility consisting of the New Revolver and the New Term Loan. On the Effective Date, the entire balance on the Prior Credit Facility in the amount of $444,440 was repaid while we received gross proceeds, before lender fees, representing the opening balances on our New Revolver of $120,000 and a New Term Loan of $150,000. 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, 2016, for further details on our pre-emergence debt facilities.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

New Term Loan

The New Term Loan, which is collateralized by our oil and natural gas properties, is scheduled to mature on March 21, 2021. Interest on the outstanding amount of the New Term Loan will accrue at an interest rate equal to either: (a) the Alternate Base Rate (as defined in the New Credit Facility) plus a 6.75% margin or (b) the Adjusted LIBO Rate (as defined in the New Credit Facility), plus a 7.75% margin with a 1.00% floor on the Adjusted LIBO Rate. As of March 31, 2017, our outstanding borrowings were accruing interest at the Alternate Base Rate which resulted in an interest rate of 10.75%. In early April 2017 our outstanding borrowings began accruing interest at the Adjusted LIBO Rate which lowered the interest rate to 8.78%.

We are required to make scheduled, mandatory principal payments in respect of the New Term Loan according to the schedule below, with the remaining outstanding balance due upon maturity:

New Revolver

The New Revolver is a $400,000 facility collateralized by our oil and natural gas properties and is scheduled to mature on March 21, 2021. Availability under our New Revolver is subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request an additional borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. The initial borrowing base on the Effective Date was $225,000 and the first borrowing base redetermination has been set for on or about May 1, 2018. Availability on the New Revolver as of March 31, 2017, after taking into account outstanding borrowings and letters of credit on that date, was $104,172.

Interest on the outstanding amounts under the New Revolver will accrue at an interest rate equal to either (i) the Alternate Base Rate plus a margin that ranges between 2.00% to 3.00% depending on utilization or (ii) the Adjusted LIBO Rate applicable to one, two, three or six month borrowings plus a margin that ranges between 3.00% to 4.00% depending on utilization. In the case that an Event of Default (as defined under the New Credit Facility) occurs, the applicable rate while in default will be the Alternate Base Rate plus an additional 2.00% and plus the applicable margin. As of March 31, 2017, our outstanding borrowings were accruing interest at the Alternate Base Rate which resulted in an interest rate of 6.50%. In early April 2017 our outstanding borrowings began accruing interest at the Adjusted LIBO Rate which lowered the interest rate to 4.53%.

Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount, based on the utilization percentage, and are included as a component of interest expense. We generally have the right to make prepayments of the borrowings at any time without penalty or premium. Letter of credit fees will accrue at 0.125% plus the margin used to determine the interest rate applicable to New Revolver borrowings that are based on Adjusted LIBO Rate.

Covenants

The New Credit Facility contains covenants and events of default customary for oil and natural gas reserve-based lending facilities including restrictions on additional debt, guarantees, liens, restricted payments, investments and hedging activity. Additionally, our New Credit Facility specifies events of default, including non-payment, breach of warranty, non-performance of covenants, default on other indebtedness or swap agreements, certain adverse judgments, bankruptcy events and change of control, among others.

The financial covenants require that we maintain: (1) a Current Ratio (as defined in the New Credit Facility) of no less than 1.00 to 1.00, (2) an Asset Coverage Ratio (as defined in the New Credit Facility) of no less than 1.35 to 1.00, (3) Liquidity (as defined in the New Credit Facility) of at least $25,000 and (4) a Ratio Total Debt to EBITDAX (as defined in the New Credit Facility) of no greater than 3.5 to 1.0 calculated on a trailing four-quarter basis. We are required to comply with these covenants for each fiscal quarter ending on and after March 31, 2017, except for the Asset Coverage Ratio, for which compliance is required semiannually.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Write-off of 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 $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 grace period on March 31, 2016, we triggered an Event of Default on our Senior Notes. While uncured, the Event of Default effectively allowed the lender to demand immediate repayment, thus shortening the life of our Senior Notes. As a result, we wrote off the remaining balance of unamortized issuance costs, premium and discount on March 31, 2016, as follows:

 

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 6: 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, collars, put options, enhanced swaps and basis protection swaps. See “Note 7—Derivative Instruments” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2016, for a description of the various kinds of derivatives we may enter into.

The following table summarizes our crude oil derivatives outstanding as of March 31, 2017:

The following table summarizes our natural gas derivatives outstanding as of March 31, 2017:

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See “Note 7—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 “Derivative (losses) gains” in the consolidated statements of operations.

“Derivative (losses) gains” in the consolidated statements of operations are comprised of the following:

 

 

Note 7: 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.

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

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

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

As of March 31, 2017, and December 31, 2016, our financial instruments recorded at fair value on a recurring basis consisted of commodity derivative contracts (see “Note 6—Derivative instruments”). We had no Level 1 assets or liabilities. Our derivative contracts classified as Level 2 consisted of commodity price swaps which are valued using an income approach. Future cash flows from the commodity price swaps are estimated based on the difference between the fixed contract price and the underlying published forward market price. Our derivative contracts classified as Level 3 consisted of collars. 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:

 

 

Changes in the fair value of our derivative instruments, classified as Level 3 in the fair value hierarchy, were as follows for the periods presented:

 

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 2017 and 2016 were escalated using an annual inflation rate of 2.30% and 2.42%, respectively. The estimated future costs to dispose of properties added during the first three months of 2017 were discounted, depending on the range of maturity of the property, with a credit-adjusted risk-free rate ranging from 5.20% to 7.40%. The discount rate used for the first three months of 2016 was our weighted average credit-adjusted risk-free interest rate of 20.00%. These estimates may change based upon future inflation rates and changes in

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

statutory remediation rules. See “Note 8—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, 2017, and December 31, 2016, were as follows:

 

 

The carrying value of our New Revolver, New Term Loan and other secured long-term debt approximates fair value because the rates are comparable to those at which we could currently borrow under similar terms, are variable and incorporate a measure of our credit risk. The fair value of our Senior Notes was estimated based on quoted market prices. We have not disclosed the fair value of outstanding amounts under our Prior Credit Facility as of December 31, 2016, as it was not practicable to obtain a reasonable estimate of such value while the Predecessor was in bankruptcy.

Counterparty credit risk

Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our credit facilities 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 counterparty that is a Lender, or an affiliate of a Lender, under our credit facilities can be offset against amounts owed to such counterparty Lender. As of March 31, 2017, the counterparties to our open derivative contracts consisted of four financial institutions, of which all were subject to our rights of offset under our New Credit Facility.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

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 credit facilities that are available to offset our net derivative assets due from counterparties that are lenders under our credit facilities.

 

_____________________________________________________

(1) Since positive and negative positions with a counterparty are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification, these represent remaining amounts that could have been offset under our master netting agreements.

We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our credit facilities. Payment on our derivative contracts could be accelerated in the event of a default on our New Credit Facility. The aggregate fair value of our derivative liabilities subject to acceleration in the event of default was $363 at March 31, 2017.

Note 8: Asset retirement obligations

The following table provides a summary of our asset retirement obligation activity:  

 

See “Note 7—Fair value measurements” for additional information regarding fair value assumptions associated with our asset retirement obligations.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

Note 9: Deferred compensation

Restricted Stock Unit Plan

Prior to our emergence from bankruptcy, we had a Non-Officer Restricted Stock Unit Plan (the “RSU Plan”) in effect as an incentive plan for nonexecutive employees. The provisions under our RSU Plan are discussed in Note 11 — Deferred compensation in Item 8. Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2016. As of January 1, 2017, there were 98,596 unvested and outstanding Restricted Stock Units with a weighted average grant date fair value of $7.18 per unit.

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 RSU as of January 1, 2017, was $0.00. All remaining unvested awards were cancelled upon our emergence from bankruptcy on the Effective Date.

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. A summary of compensation expense for the 2015 Cash LTIP is presented below:

 

On April 3, 2017, the Company awarded an additional $3,321 under 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 reserved 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, were eligible to participate in the 2010 Plan.

The awards granted under the 2010 Plan consisted of shares that were 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 material provisions under the 2010 Plan are discussed in “Note 11—Deferred compensation” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2016.

As of result of our bankruptcy, the estimated fair value of our Time Vested restricted awards was $0.00 per share since the Petition Date. Furthermore, during the third quarter of 2016, we recorded a cumulative catch up adjustment of to reverse the aggregate compensation cost associated with our Performance Vested awards in order to reflect a decrease in the probability that requisite service would be achieved for these awards. Pursuant to our Reorganization Plan, all outstanding restricted shares were cancelled. As this cancellation was not accompanied by the concurrent grant of (or offer to grant) a replacement award or other valuable consideration, it was accounted for as a repurchase for no consideration. Accordingly, any previously unrecognized compensation cost was recognized at the cancellation date.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

A summary of our restricted stock activity for the Predecessor period in 2017 is presented below:

 

 

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.

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:  

 

The credit for stock-based compensation for the three months ended March 31, 2016, was primarily a result of forfeitures from our workforce reduction in January 2016. As of March 31, 2017, and December 31, 2016, accrued payroll and benefits payable included $0 and $0, respectively, for stock-based compensation costs expected to be settled within the next twelve months. We did not have any unrecognized compensation cost as of March 31, 2017, as all previously outstanding equity based awards were cancelled.

 

Note 10: 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, 2017, and December 31, 2016. 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, 2017 or 2016.

Litigation and Claims

Chapter 11 Proceedings. Commencement of the Chapter 11 Cases automatically stayed many of the proceedings and actions against us noted below as well as other claims and actions that were or could have been brought prior to May 9, 2016, and the claims remain subject to bankruptcy court jurisdiction. In connection with the proofs of claim asserted during bankruptcy from the proceedings or actions below, we are unable to estimate the amounts that will be allowed through the Bankruptcy proceedings due to the complexity and number of legal and factual issues presented by the matters and uncertainties with respect to, amongst other things, the nature of the claims and defenses, the potential size of the classes, the scope and types of the properties and agreements involved, and the ultimate potential outcomes of the matters. As a result, no reserves were established within our liabilities in connection with

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

the proceedings and actions described below. To the extent that any of these legal proceedings result in a claim being allowed against us, pursuant to the terms of the Reorganization Plan, such claims will be satisfied through the issuance of new stock in the Company.

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 Trial Court”) 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 (“Naylor Farms Case”). 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. Plaintiffs filed a motion for class certification in October 2015. In addition, the plaintiffs filed a motion for summary judgment asking the court to determine as a matter of law that natural gas is not marketable until it is in the condition and location to enter an interstate pipeline. Responsive briefs to both motions were filed in the fourth quarter of 2015. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. In response, on May 23, 2016, the court issued an order administratively closing the case, subject to reopening depending on the disposition of the bankruptcy proceedings. On July 22, 2016, attorneys for the putative class filed a motion in the Bankruptcy Court asking the court to lift the automatic stay and allow the case to proceed in the Naylor Trial Court. We did not object to lifting the automatic stay with regard to this case for the limited purpose of allowing the Naylor Trial Court to rule on the pending motion for class certification. On January 17, 2017, the Naylor Trial Court certified a modified class of plaintiffs with oil and gas leases containing specific language. The modified class constitutes less than 60% of the leases the Plaintiffs originally sought to certify. On January 30, 2017, the Company filed a motion for reconsideration with the Naylor Trial Court, asking the court to rule the class cannot be immediately certified because Plaintiffs did not define dates for class membership. Plaintiffs responded the class should include claims reaching back to December 1, 1999, to which we responded the statute of limitations should limit the beginning of the class period to June 1, 2006. The Naylor Trial Court issued an order conditionally denying reconsideration, contingent on Plaintiffs selection of June 1, 2006 as the commencement of the class period. Plaintiffs amended the class to include only claims relating back to June 1, 2006. On April 18, 2017, the Naylor Trial Court denied our motion for reconsideration and also issued an order administratively closing the case pending disposition of the bankruptcy proceedings. On May 1, 2017, we filed a Petition for Permission to Appeal Class Certification Order with the Tenth Circuit Court of Appeals (“Appellate Petition”). The Tenth Circuit has not ruled on our Appellate Petition.

The plaintiffs 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 damages would be comprised of interest. In addition to filing claims on behalf of the named plaintiffs and associated parties, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $150,000 in our Chapter 11 Cases. The Company has objected treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. The Bankruptcy Court heard testimony and arguments regarding class-wide treatment of the claim on February 28, 2017, but has not ruled on the matter. Under the Reorganization Plan, the Plaintiffs are identified as a separate class of creditors, Class 8. Under the Reorganization Plan, Class 8 claims are entitled to receive their pro rata share of new stock issued to the holders of general unsecured claims (including claims of the Noteholders). Although the members of Class 8 voted to reject the Plan, the Bankruptcy Court confirmed the Plan on March 10, 2017, without objection by the Plaintiffs. If the Bankruptcy Court permits the Plaintiffs’ proof of claim to proceed on behalf of the class and the plaintiffs ultimately prevail on the merits of their claims, any liability arising under judgment or settlement of the unsecured claims would be satisfied through the issuance of new stock in the Company. We continue to dispute the plaintiffs’ allegations, dispute the case meets the requirements for class certification, and are objecting to the claims both individually and on a class-wide basis.

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 an allegation similar to those asserted in the Naylor Farms case related to post-production deductions, and include claims 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 the time we filed our Bankruptcy Petitions, a class had not been certified and discovery had not yet commenced. As the plaintiffs in the Dodson case did not file proofs of claim either for the putative class or the putative class representative, we anticipate any liability related to this claim will be addressed only based on proofs of claim filed by individual royalty owners.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

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 allegedly required under the National Environmental Protection (NEPA). The 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. The plaintiffs also filed a motion to file an amended complaint to cure the deficiencies which the court found in the dismissed complaint. Several defendants have filed briefs objecting to plaintiffs’ motions. On May 20, 2016, the Company filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code, and has not responded to the plaintiffs’ motions. After a motion for reconsideration was denied, Plaintiffs filed a Notice of Appeal on December 6, 2016. On December 30, 2016, the Court of Appeals entered an Order Abating Appeal due to pending bankruptcy proceedings of multiple defendants. On January 13, 2017, Plaintiffs responded to the Order Abating Appeal, asking the Court to proceed with the appeal. The Court has not ruled on the appeal as of the date of this report. The Court lifted the Stay as to Chaparral on April 13, 2017, and we joined the answer filed by other non-federal defendants which had been filed on March 24, 2017.

As the plaintiffs in the Donelson case did not file proofs of claim either for the putative class or the putative class representatives, we anticipate any monetary liability related to this claim will be discharged. We dispute plaintiffs’ allegations and dispute that the case meets the requirements for a class action.

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 eight counties in central 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 did not ask for damages related to actual property damage which may have occurred. We 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 (“CAFA”). On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy, informing the court that we had filed voluntary petitions for relief under Chapter 11 of the United States Bankruptcy Code. On October 14, 2016, the plaintiffs filed an Amended Complaint adding additional defendants and increasing the Class Area to 25 Central Oklahoma counties. Although we are named as a defendant, the Amended Complaint expressly limits its claims against us to those asserted in the original petition unless and until the automatic stay is lifted. Plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $75,000 in our Chapter 11 Cases. Other defendants have filed motions to dismiss the action based on various theories, as well as motions to strike various allegations and requested relief as unsupported by Oklahoma law. A hearing on the various motions to dismiss and motions to strike was held on May 12, 2017. The judge made various rulings from the bench, including dismissing the complaint for failure to adequately allege causation, but permitting the plaintiffs to amend the complaint to cure the deficiency. We dispute the 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. In addition, other proofs of claim have been filed in our bankruptcy case which we anticipate repudiating. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows.

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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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, unless otherwise noted)

 

obligations primarily relate to a contract for the purchase of CO₂ and drilling rig services. Other than changes to our credit facility (see “Note 5—Debt”) and the discharge of our Senior Notes and certain general unsecured claims pursuant our Reorganization Plan (see “Note 3—Chapter 11 reorganization”), the only other material change to our contractual commitments since December 31, 2016, relates to our contracts for drilling rig services. As of March 31, 2017, our obligations under our drilling rig contracts were $2,581.

 

 

 

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The following discussion and analysis is intended to assist in understanding our financial condition and results of operations for the periods of March 22, 2017, through March 31, 2017 (Successor), and January 1, 2017, through March 21, 2017 (Predecessor), and the three months ended March 31, 2016 (Predecessor), and should be read in conjunction with our unaudited consolidated financial statements and the notes thereto included in this quarterly report with the consolidated financial statements, notes and management's discussion and analysis of financial condition and results of operations included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2017, though as described below, such prior financial statements may not be comparable to our interim financial statements due to the adoption of fresh-start accounting. References to "Successor" or "Successor Company" relate to the financial position and results of operations of the reorganized company subsequent to March 21, 2017. References to "Predecessor" or "Predecessor Company" relate to the financial position and results of operations of the Company prior to, and including, March 21, 2017.

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. For more information, see “Cautionary Note Regarding Forward-Looking Statements.”

Overview

Founded in 1988 and headquartered in Oklahoma City, we are a 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. We also have significant production from CO₂ EOR methods 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 reserves as of December 31, 2016, were 43% proved developed, 74% crude oil, 17% natural gas and 9% natural gas liquids.

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, 2016, reserve estimates reflect that our production rate on current proved developed properties will decline at annual rates of approximately 15%, 13%, and 15% 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:

Chapter 11 Reorganization

Bankruptcy petition and emergence. On May 9, 2016 (the “Petition Date”), Chaparral Energy, Inc. and its subsidiaries including Chaparral Energy, L.L.C., Chaparral Resources, L.L.C., Chaparral Real Estate, L.L.C., Chaparral CO2 , L.L.C., CEI Pipeline, L.L.C., CEI Acquisition, L.L.C., Green Country Supply, Inc., Chaparral Biofuels, L.L.C., Chaparral Exploration, L.L.C., Roadrunner Drilling, L.L.C. (collectively, the “Chapter 11 Subsidiaries” and, together with Chaparral Energy, Inc., the “Debtors”) filed voluntary petitions seeking relief under Title 11 of the United States Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) commencing cases for relief under chapter 11 of the Bankruptcy Code (the “Chapter 11 Cases”).

On March 10, 2017, (the “Confirmation Date”), the Bankruptcy Court confirmed our Reorganization Plan and on March 21, 2017 (the “Effective Date”), the Reorganization Plan became effective and we emerged from bankruptcy.

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Debtor-In-Possession.  During the pendency of the Chapter 11 Cases, we operated our business as debtors in possession in accordance with the applicable provisions of the Bankruptcy Code. The Bankruptcy Court granted all first day motions filed by us which were designed primarily to minimize the impact of the Chapter 11 Cases on our normal day-to-day operations, our customers, regulatory agencies, including taxing authorities, and employees. As a result, we were able to conduct normal business activities and pay all associated obligations for the post-petition period and we were also authorized to pay and have paid (subject to limitations applicable to payments of certain pre-petition obligations) pre-petition employee wages and benefits, pre-petition amounts owed to certain lienholders and critical vendors, amounts due to taxing authorities for production and other related taxes and funds belonging to third parties, including royalty and working interest holders. During the pendency of the Chapter 11 Cases, all transactions outside the ordinary course of our business required the approval of the Bankruptcy Court.

Automatic Stay. 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 us or our property to recover, collect or secure a claim arising prior to the Petition Date. Absent an order from the Bankruptcy Court, substantially all of our pre-petition liabilities were subject to settlement under the Bankruptcy Code.

Plan of Reorganization. Pursuant to the terms of the Reorganization Plan, which was supported by us, certain lenders under our Prior Credit Facility  (collectively, the “Lenders”) and certain holders of the Company’s Senior Notes (collectively, the “Noteholders”), the following transactions were completed subsequent to the Confirmation Date and prior to or at the Effective Date:

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In support of the Reorganization Plan, the Company estimated the enterprise value of the Successor to be in the range of $1.05 billion to $1.35 billion, which was subsequently approved by the Bankruptcy Court.

Fresh-start Accounting

Upon our emergence from bankruptcy, on March 21, 2017, we adopted fresh-start accounting in accordance with the provisions set forth in Accounting Standards Codification 852, Reorganizations, as (i) the Reorganization Value of our assets immediately prior to the date of confirmation was less than the post-petition liabilities and allowed claims and (ii) the holders of our existing voting shares of the Predecessor entity received less than 50% of the voting shares of the emerging entity.

Adopting fresh-start accounting results in a new financial reporting entity with no beginning or ending retained earnings or deficit balances as of the fresh-start reporting date. Upon the adoption of fresh-start accounting, our assets and liabilities were recorded at their fair values as of the fresh-start reporting date. Our adoption of fresh-start accounting may materially affect our results of operations following the fresh-start reporting date, as we will have a new basis in our assets and liabilities. As a result of the adoption of fresh-start reporting and the effects of the implementation of the Plan, our unaudited consolidated financial statements subsequent to March 21, 2017, may not be comparable to our unaudited consolidated financial statements prior to March 21, 2017, as such, "black-line" financial statements are presented to distinguish between the Predecessor and Successor companies. In order to facilitate the discussion and analysis herein, we have addressed the Predecessor and Successor periods discretely and have provided comparative analysis, to the extent practical, where appropriate.

Price Uncertainty and the Full-Cost Ceiling Impairment

We deal with volatility in commodity prices primarily by insuring our overall cost structure is competitive and supportive in a $40/bbl to $60/bbl oil price environment. In addition, we maintain 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. 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.  We currently have derivative contracts in place for oil and natural gas production in 2017, 2018 and 2019 (see Item 3. Quantitative and Qualitative Disclosures About Market Risk).

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. The average price utilized in our ceiling test calculation over the past 12 months is as follows:

As discussed above, our application of fresh start accounting to our balance sheet on March 21, 2017, resulted in the carrying value of our oil and natural gas properties being restated based on their fair value. The estimated fresh start fair value along with adjustments for activity between the March 21, 2017, and the end of the first quarter of 2017 as well as the increase in SEC average prices resulted in a carrying value that was below the full cost ceiling at quarter-end and thus a ceiling test write-down was not required.

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, outside of transactions related to our emergence from bankruptcy, in the first quarter of 2017 includes the following highlights:

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Future of Active EOR

We announced on April 28, 2017, that during the remainder of 2017, we will be pursuing strategic alternatives for our EOR assets as we shifts our strategy and portfolio to focus solely on our more profitable STACK Area. In that regard, we retained CIBC Griffis & Small as an advisor to assist in marketing its EOR assets which will commence in June or July of the current year.

Capital development

During the three months ended March 31, 2017, we incurred capital expenditures of $43.2 million. This included expenditure for completing three wells spudded in the previous year, drilling and completing one well, and drilling an additional two wells to be completed in the second quarter, as well as participating in outside operated wells, all within our STACK play. We began the year with one rig, which increased to two rigs during the first quarter and we expect to continue to drill two rigs through the second quarter. Depending on commodity pricing and asset sale proceeds, we may continue to run two rigs in the play.  We also incurred capital expenditures within our Active EOR Areas for continuing CO₂ purchases, developing our North Burbank Unit and efficiently producing our other units experiencing production decline. Our oil and natural gas capital budget for 2017 is $145.9 million which we plan to fund with a combination of cash flows from operations and proceeds from the sale of non-core assets from which we expect to generate $25 million to $30 million in net proceeds.

Results of operations

Production

Production volumes by area were as follows:

 

We have recently realigned our operating plays/areas to better highlight those areas where we are focusing our operations and where our current and future capital will be spent. Please see Items 1. and 2. Business and Properties of our Annual Report on Form 10-K for the year ended December 31, 2016, for a discussion of operating areas.

Our total net production of 227 MBoe for the Successor and 1,796 MBoe for the Predecessor periods in 2017, for a total of 2,023 MBoe in 2017, declined from the prior year quarter. The decline was due to production declines in all our areas outside the STACK. Areas outside the STACK, other than our North Burbank Unit, experienced declining production due to a decrease in development activity. In addition, a severe ice storm in the Oklahoma Panhandle during the Predecessor period in 2017 had an adverse impact on our oil production in our Active EOR and Other areas. Production in our STACK play increased as a result of the 11 wells that came online during the period and our participation in new outside-operated wells in this play. In our Active EOR Areas, increases in production at our North Burbank Unit as a result of ongoing investment partially mitigated the decreases experienced at our Booker, Camrick and Farnsworth units.  

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Revenues

Our commodity sales are derived from the production and sale of oil, natural gas and natural gas liquids. 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 commodity sales of $7.8 million for the Successor and $66.5 million for the Predecessor periods in 2017, for a total of $74.3 million in 2017, were higher than the prior year quarter primarily due to increases in prices on all commodities offset partially by the production decline as shown below:

 

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

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portion of this exposure, we have entered into various types of derivative instruments, including commodity price swaps and costless collars.

Due to defaults under the master agreements governing our derivative contracts, our outstanding derivative positions were terminated in May 2016. In December 2016, an agreement was reached with our lenders regarding the resumption of hedging activity prior to our emergence from bankruptcy and thus we began entering into new derivative instruments.

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 “Derivative (losses) gains” in our consolidated statements of operations. The fluctuation in derivative (losses) gains 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.

Total lease operating expense is not comparable across the time periods presented above in part due to the bonus adjustment depicted in the table above. Provisions set by the Bankruptcy Court during the pendency of our bankruptcy prevented us from paying bonuses in the ordinary course of business. Pursuant to these provisions, we did not accrue bonuses during 2016 and during the entire pendency of our bankruptcy. Upon emergence, we recognized expense for the entire amount of our 2016 fiscal year bonus (paid in March 2017) as well as accrued a pro rata portion of our 2017 fiscal year bonus reflecting the first three months of 2017; both adjustments totaled $2.0 million as disclosed in the table above.

Absent the bonus adjustment, lease operating expenses, which were $2.2 million and $19.9 million in the Successor and Predecessor periods in 2017, respectively, totaling $22.2 million for the three months ended March 31, 2017, were lower compared to the three months ended March 31, 2016, primarily due to reductions in our Active EOR Project Areas and Other areas.

Lease operating expenses for our STACK Areas were flat from 2016 to 2017. Although we incurred additional costs of oil field goods and services as a result of new wells coming online in 2016, these increases were offset by cost savings from improved efficiencies, which resulted in lease operating expenses being approximately unchanged from period to period. Increased production, improved efficiencies and economies of scale in this area also resulted in a decrease in cost on a Boe basis from 2016 to 2017.

Lease operating expenses for our Active EOR areas decreased from 2016 to 2017 as a result of declining production on our older, higher cost EOR projects later in their lifecycle, partially offset by the increase in production and related economies of scale in our North Burbank Unit.

The decrease in our Other Areas was primarily due to declining production due to a decrease in development activity.

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. Transportation and processing costs of $0.4 million and $2.0 million for the Successor and Predecessor periods in 2017, respectively, which totaled $2.4 million, increased from the three months ended March 31, 2016, due to production from new wells in our STACK with substantially higher per unit processing costs.

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Production taxes (which include severance and valorem taxes)

 

Production taxes of $0.3 million and $2.4 million for the Successor and Predecessor periods in 2017, respectively, which totaled $2.7 million, increased compared to the three months ended March 31, 2016, as a result of an increase in revenues. As discussed earlier, the increase in revenues is attributable to higher prices which were partially offset by lower volumes.

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 is not comparable between Successor and Predecessor periods as a result our implementation of fresh start accounting upon bankruptcy emergence whereupon the carrying value of our proved oil and gas properties on our balance sheet was restated to fair value. The restatement resulted in an increase in the full cost amortization base which led to a corresponding increase in the DD&A rate per equivalent unit of production for the period from March 22 to March 31, 2017. Overall DD&A for the Successor and Predecessor periods in 2017, which was $3.4 million and $24.9 million, respectively, and totaling $28.3 million, was lower than the three months ended March 31, 2016, primarily due to a decrease in production volumes between the two periods.

Asset impairments

 

Oil and natural gas 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. The average price utilized in our ceiling test calculation over the past 12 months has generally followed the following pattern:

As discussed above, our application of fresh start accounting to our balance sheet on March 21, 2017, resulted in the carrying value of our oil and natural gas properties being restated based on their fair value. The estimated fresh start fair value along with

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adjustments for activity between the March 21, 2017, and the end of the first quarter of 2017, as well as the increase in SEC average prices from year-end 2016 resulted in a carrying value that was below the full cost ceiling at quarter-end and thus a ceiling test write-down was not required as of March 31, 2017. The ceiling test impairment for the three months ended March 31, 2016, of $77.9 million was primarily due to the decrease in SEC prices.

General and administrative expenses (“G&A”)

 

Net G&A expense is not comparable across the time periods presented above in part due to the bonus adjustment. Provisions set by the Bankruptcy Court during the pendency of our bankruptcy prevented us from paying bonuses in the ordinary course of business. Pursuant to these provisions, we did not accrue bonuses during 2016 and during the entire pendency of our bankruptcy. Upon emergence, we recognized expense for the entire amount of our 2016 fiscal year bonus (paid in March 2017) as well as accrued a pro rata portion of our 2017 fiscal year bonus reflecting the first three months of 2017; both adjustments totaled $6.6 million as disclosed in the table above. Gross G&A of $0.9 million and $8.1 million for the Successor and Predecessor periods in 2017, totaling $9.0 million for the three months ended March 31, 2017, was higher than the prior year quarter primarily due to an increase in professional fees.

Capitalized exploration and development costs were higher during the Successor and Predecessor periods in 2017 compared to the three months ended 2016 primarily due the bonus adjustment for which a portion was capitalized.

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to the deterioration of commodity prices. We implemented workforce reductions during both the current year and prior year periods and therefore recorded one-time severance and termination benefits in connection with the layoffs. The remaining cost reduction expense is a result of professional services we engaged to assist in these initiatives as follows (in thousands):

 

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 petition. Such costs, to the extent that they are incremental and directly related to our bankruptcy, were recorded as “Reorganization items, net” on our consolidated statement of operations subsequent to the Petition Date.

Income Taxes

The income tax expense that was recognized for the Predecessor and Successor periods in our consolidated statement of operations is a result of current Texas margin tax on gross revenues less certain deductions. We did not record any net deferred tax benefit in the Predecessor and Successor periods in 2017 as any deferred tax asset arising from the benefit is reduced by a valuation

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allowance. 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, 2016, which contains additional information about our income taxes.

Other income and expenses

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

 

Total interest expense is not comparable across the time periods disclosed above. During the period from March 22 to March 31, 2017, we incurred interest related to our New Term Loan and New Revolver whereas these facilities had not been established prior to our emergence from bankruptcy. During the period from January 1 to March 21, 2017, we incurred interest related to our Prior Credit Facility but did not record any interest on our Senior Notes as we ceased accruing interest on our Senior Notes upon the filing of our bankruptcy petition. During the three months ended March 31, 2016, we incurred interest related to our Senior Notes and Prior Credit Facility. Interest expense of $0.7 million and $5.9 million for the Successor and Predecessor periods in 2017, respectively, which totaled $6.5 million for the three months ended March 31, 2017, was lower than the comparable period in 2016 primarily due to the absence of interest expense on the Senior Notes in the current year periods. We also had a reduction in capitalized interest as a result of a lower carrying amount of unevaluated purchased non-producing leasehold subsequent to the leasehold impairments recorded in 2016. As a result of applying fresh start accounting upon our emergence from bankruptcy, the carrying value of our unevaluated non-producing leasehold was significantly increased to reflect the fair value of our acreage in the STACK. In future periods subsequent to the adoption of fresh start accounting, we will not be capitalizing interest related to the fresh start gross up of the carrying value of unevaluated acreage as capitalized interest will only be calculated based on the carrying value of actual purchased leasehold.

Senior Notes 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 allowed 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.

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Reorganization Items

Reorganization items reflect, where applicable, post-petition revenues, expenses, gains and losses incurred that are incremental and a direct result of the reorganization of the business. As a result of our emergence from bankruptcy, we have also recorded gains on the settlement of liabilities subject to compromise and gains from restating our balance sheet to fair values under fresh start accounting. These adjustments are discussed in “Note 3—Fresh start accounting” in Item 1. Financial Statements of this report. We have incurred significant costs associated with the reorganization and expect to incur an additional $6 million to $8 million of reorganization-related professional fees for the remainder of the year. These costs, which are presented below, are expected to significantly affect our results of operations (in thousands):

 

Liquidity and capital resources

Historically, our primary sources of liquidity have been cash generated from our operations, borrowings under our credit facility, private equity sales and proceeds from asset dispositions. Our primary use of cash flow has been to fund capital expenditures used to develop our oil and natural gas activities and to meet day-to day operating expenses. Upon emergence from bankruptcy, our primary sources of liquidity are cash flows from operations and borrowings under the New Credit Facility. Other potential sources of liquidity in the next twelve months include proceeds from sales of non-core assets. Our cash balance as of March 31, 2017, was approximately $32 million of which $14 million was restricted for the payment of debtor-related professional fees and convenience class claims pursuant to our Reorganization Plan. We also had borrowing availability under our New Revolver of $104.2 million. As of May 11, 2017, our cash balance was approximately $22.3 million, of which $11.4 million was restricted, with $120.0 million outstanding on our New Revolver and borrowing availability of $104.2 million. We believe that we have sufficient liquidity to fund our capital expenditures and day to day operations for the next 12 months.

Our cash flows from operating activities are subject to significant volatility due to changes in commodity prices for our crude oil, NGL and natural gas products, as well as variations in our production. The prices for these commodities are driven by a number of factors beyond our control, including global and regional product supply and demand, weather, product distribution, refining and processing capacity and other supply chain dynamics, among other factors. The level of our hedging activity and duration of the instruments employed depend on our desired cash flow protection, available hedge prices, the magnitude of our capital program and our operating strategy. We currently have derivative contracts in place for oil and natural gas production in 2017, 2018 and 2019 (see Item 3. Quantitative and Qualitative Disclosures About Market Risk).

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 for the three months ended March 31, 2017, which included outflows of $8.4 million for Successor period and inflows of $14.4 million for the Predecessor period, increased over the prior year quarter as a result of an increase in revenues and a decrease in cost reduction initiatives expense. These increases were partially offset by the additional expenses to restructure our debt and in preparation for our bankruptcy petition as well as an increase in cash interest paid.

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When available, we use the net cash provided by operations to partially fund our acquisition, exploration and development activities. With limited cash flows from operating activities due to low commodity prices and constraints imposed on us while in bankruptcy, our capital expenditures for the three months ended March 31, 2017, were also funded by the excess cash that we were carrying prior to our emergence.

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.

Our actual costs incurred, including costs that we have accrued for during the three months ended March 31, 2017, and our budgeted 2017 capital expenditures for oil and natural gas properties are summarized in the table below.

 

Net cash used in investing activities during the Successor period in 2017 was comprised of cash outflows for capital expenditure of $5.8 million and cash inflows from derivative settlement receipts of $1.7 million. Net cash used in investing activities during the Predecessor period in 2017 was comprised of cash outflows for capital expenditure of $31.2 million, cash inflows from derivative settlement receipts of $1.3 million and cash inflows from asset sales of $1.9 million. Net cash provided by investing activities during the three months ended March 31, 2016, of the Predecessor, was comprised primarily of cash outflows for capital expenditure of $47.1 million, cash inflows from derivative settlement receipts of $47.5 million and cash inflows from asset sales of $0.5 million.

We had minimal cash flows from financing activities during the Successor period in 2017. Cash flows from financing activities during the Predecessor period in 2017 is comprised primarily of cash outflows for repayments of debt and capital leases of $445.4 million and payment of $2.4 million in debt issuance costs partially offset by cash inflows of $270.0 million from new borrowings. The large repayments and borrowings of debt reflect the extinguishment of our Prior Credit Facility and establishment of our New Credit Facility upon our emergence from bankruptcy. During the three months ended March 31, 2016, of the Predecessor, 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.

Indebtedness

Debt consists of the following as of the dates indicated:

 

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Liabilities Subject to Compromise

The following table summarizes the components of “Liabilities subject to compromise” included on our Consolidated Balance Sheet immediately prior to emergence on March 21, 2017:

As discussed earlier, claims from the Senior Notes and associated interest along with approximately $3 million in general unsecured claims were settled upon emergence through the issuance of Successor common stock. The remaining claims were either paid or reinstated in full.

Credit Facilities

Our Prior Credit Facility, previously consisting of a senior secured revolving credit facility with an outstanding balance of $444 million prior to emergence, was restructured into a New Credit Facility consisting of the New Revolver and New Term Loan. On the Effective Date, the entire balance on the Prior Credit Facility was repaid while we received gross proceeds, before lender fees, representing the opening balances on our New Revolver of $120 million and a New Term Loan of $150 million.

 New Term Loan. The loan, which is collateralized by our oil and natural gas properties, is scheduled to mature on March 21, 2021. Interest on the outstanding amount of the New Term Loan will accrue at an interest rate equal to either: (a) the Alternate Base Rate (as defined in the New Credit Facility) plus a 6.75% margin or (b) the Adjusted LIBO Rate (as defined in the New Credit Facility), plus a 7.75% margin with a 1.00% floor on the Adjusted LIBO Rate. We are required to make scheduled, mandatory principal payments in the amount of $1.2 million in calendar 2017, $1.5 million in 2018, $3.8 million in 2019 and $6.8 million in 2020 with the remaining outstanding balance due upon maturity.

New Revolver. The New Revolver is a $400.0 million facility collateralized by our oil and natural gas properties and is scheduled to mature on March 21, 2021. Availability under our New Revolver is subject to a borrowing base based on the value of our oil and natural gas properties and set by the banks semi-annually on May 1 and November 1 of each year. In addition, the lenders may request a borrowing base redetermination once between each scheduled redetermination or upon the occurrence of certain specified events. The banks establish a borrowing base by making an estimate of the collateral value of our oil and natural gas properties. If oil and natural gas prices decrease from the amounts used in estimating the collateral value of our oil and natural gas properties, the borrowing base may be reduced, thus reducing funds available under the borrowing base. The initial borrowing base on the Effective Date was $225.0 million and the first borrowing base redetermination has been set for on or about May 1, 2018.

Interest on the outstanding amounts under the New Revolver will accrue at an interest rate equal to either (i) the Alternative Base Rate plus a margin that ranges between 2.00% to 3.00% depending on utilization or (ii) the Adjusted LIBO Rate applicable to one, two three or six month borrowings plus a margin that ranges between 3.00% to 4.00% depending on utilization. In the case that an Event of Default (as defined under the New Credit Facility) occurs, the applicable rate while in default will be the Alternative Base Rate plus an additional 2.00% and plus the applicable margin.

Commitment fees of 0.50% accrue on the unused portion of the borrowing base amount, based on the utilization percentage, and are included as a component of interest expense. We generally have the right to make prepayments of the borrowings at any time without penalty or premium. Letter of credit fees will accrue at 0.125% plus the margin used to determine the interest rate applicable to New Revolver borrowings that are based on Adjusted LIBO Rate.

If the outstanding borrowings under our New Revolver were to exceed the borrowing base as a result of a redetermination, we would be required to eliminate this deficiency. Within 10 days after receiving notice of the new borrowing base, we would be required to make an election: (1) to repay the deficiency in a lump sum within 45 days or (2) commencing within 45 days to repay the deficiency in equal monthly installments over a six -month period or (3) to submit within 45 days additional oil and gas properties we own for consideration in connection with the determination of the borrowing base sufficient to eliminate the deficiency.

The New Credit Facility contain covenants and events of default customary for oil and natural gas reserve-based lending facilities including restrictions on additional debt, guarantees, liens, restricted payments, investments and hedging activity. Additionally, our New Credit Facility specifies events of default, including non-payment, breach of warranty, non-performance of covenants, default on other indebtedness or swap agreements, certain adverse judgments, bankruptcy events and change of control, among others. The financial covenants require that we maintain: (1) a Current Ratio (as defined in the New Credit Facility) of no less than 1.00 to 1.00, (2) an Asset Coverage Ratio (as defined in the New Credit Facility) of no less than 1.35 to 1.00, (3) Liquidity (as defined in the New Credit Facility) of at least $25.0 million and (4) a Ratio Total Debt to EBITDAX (as defined in the New Credit

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Facility) of no greater than 3.5 to 1.0 calculated on a trailing four-quarter basis. We are required to comply with these covenants for each fiscal quarter ending on and after March 31, 2017, except for the Asset Coverage Ratio, for which compliance is required semiannually.

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 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 $3.2 million annually.

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 obligations primarily relate to contracts for the purchase of CO₂ and drilling rig services.

Other than changes to our credit facility and the discharge of our Senior Notes and certain general unsecured claims pursuant our Reorganization Plan, the only other material change to our contractual commitments since December 31, 2016, relates to our contracts for drilling rig services. As of March 31, 2017, our obligations under our drilling rig contracts were $2.6 million.

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Financial position

Although not directly comparable between Successor and Predecessor, we believe that the following discussion of material changes in our balance sheet may be useful:

Non-GAAP financial measure and reconciliation

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.

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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, (11) other significant, unusual non-cash charges, (12) proceeds from any early monetization of derivative contracts with a scheduled maturity date more than 12 months following the date of such monetization—this exclusion is consistent with our prior treatment, for EBITDA reporting, of any large monetization of derivative contracts and (13) certain expenses related to our cost reduction initiatives, reorganization and fresh start accounting activities for which our lenders have permitted us to exclude when calculating covenant compliance. The following table provides a reconciliation of net income to adjusted EBITDA for the specific periods:

 

Our New Credit Facility requires us to maintain a current ratio, as defined in New 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 New Credit Facility, we consider the current ratio calculated under our New 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:

 

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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, 2016.

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.

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 New 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, 2017, our gross revenues from oil and natural gas sales would change approximately $1.5 million for each $1.00 change in oil and natural gas liquid prices and $0.3 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, which in the past have included commodity price swaps, collars, put options, enhanced swaps and basis protection swaps. We do not apply hedge accounting to any of our derivative instruments. As a result, all gains and losses associated with our derivative contracts are recognized immediately as “Derivative (losses) gains” in the consolidated statements of operations. This can have a significant impact on our results of operations due to the volatility of the underlying commodity prices. Please see “Note 6—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 reviewed when deciding to enter into the original derivative position.

The fair value of our outstanding derivative instruments at March 31, 2017, was a net asset of $19.5 million. Based on our outstanding derivative instruments as of March 31, 2017, summarized below, a 10% increase in the March 31, 2017, forward curves used to mark-to-market our derivative instruments would have decreased our net asset position to a net liability of $13.0 million, while a 10% decrease would have increased our net asset position to $52.1 million.

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Our outstanding oil derivative instruments as of March 31, 2017, are summarized below:

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Our outstanding natural gas derivative instruments as of March 31, 2017, are summarized below:

Interest rates.  As of March 31, 2017, borrowings bear interest at the Alternate Base Rate, as defined under the New Credit Facility, plus the applicable margin. Any increases in these rates can have an adverse impact on our results of operations and cash flow. Assuming a constant debt level under our New Credit Facility of $270.0 million, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $2.7 million.

Disclosure controls and procedures

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 2017, at the reasonable assurance level.

Changes in Internal control over financial reporting

There have been no changes in our internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) 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 10—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

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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.

During the first quarter of 2017, there have been no material changes in our risk factors disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016, except for the following:

Risks Related to our Emergence from Chapter 11 Bankruptcy

We recently emerged from bankruptcy, which could adversely affect our business and relationships.

It is possible that our having filed for bankruptcy and our recent emergence from the Chapter 11 bankruptcy proceedings could adversely affect our business and relationships with customers, vendors, royalty or working interest owners, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Reorganization Plan and the transactions contemplated thereby and our adoption of fresh start accounting.

In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Reorganization Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the feasibility of the Reorganization Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of the bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. Although the financial projections disclosed in our disclosure statement filed with the Bankruptcy Court represent our view based on then current known facts and assumptions about the future operations of the Company there is no guarantee that the financial projections will be realized. We may not be able to meet the projected financial results or achieve projected revenues and cash flows assumed in projecting future business prospects. To the extent we do not meet the projected financial results or achieve projected revenues and cash flows, we may lack sufficient liquidity to continue operating as planned and may be unable to service our debt obligations as they come due or may not be able to meet our operational needs. Any one of these failures may preclude us from, among other things: (a) taking advantage of future opportunities; (b) growing our businesses; or (c) responding to future changes in the oil and gas industry. Further, our failure to meet the projected financial results or achieve projected revenues and cash flows could lead to cash flow and working capital constraints, which constraints may require us to seek additional working capital. We may not be able to obtain such working capital when it is required.

In addition, upon our emergence from bankruptcy, we adopted fresh start accounting, as a consequence of which our assets and liabilities were adjusted to fair values and the opening balance of our accumulated deficit upon emergence from bankruptcy was restated to zero. Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in the Company’s historical financial statements.

Upon our emergence from bankruptcy, the composition of our Board of Directors changed significantly.

Pursuant to the Reorganization Plan, the composition of the Board changed significantly. Upon emergence, the Board is now made up of seven directors, with a new non-executive Chairman of the Board, and of which six will not have previously served on the Board. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on the Board and, thus, may have different views on the issues that will determine the future of the Company. There is no guarantee that the new Board will pursue, or will pursue in the same manner, our current strategic plans. As a result, the future strategy and plans of the Company may differ materially from those of the past.

The ability to attract and retain key personnel is critical to the success of our business and may be affected by our emergence from bankruptcy.

The success of our business depends on key personnel. The ability to attract and retain these key personnel may be difficult in light of our emergence from bankruptcy, the uncertainties currently facing the business and changes we may make to the

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organizational structure to adjust to changing circumstances. Our ability to retain key personnel is further challenged by our recent announcement regarding our plans to pursue strategic alternatives for our EOR assets which comprise a significant portion of our business. We may need to enter into retention or other arrangements that could be costly to maintain. If executives, managers or other key personnel resign, retire or are terminated, or their service is otherwise interrupted, we may not be able to replace them in a timely manner and we could experience significant declines in productivity.

Our ability to utilize our net operating loss carryforwards (“NOLs”) may be limited as a result of our emergence from bankruptcy.

In general, Section 382 of the Internal Revenue Code (“IRC”) of 1986, as amended, 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 resulted in a change in ownership for purposes of the IRC Section 382. The Company analyzed alternatives available within the IRC to taxpayers in Chapter 11 bankruptcy proceedings in order to minimize the impact of the ownership change and cancellation of indebtedness income on its tax attributes. Upon filing its 2017 U.S. Federal income tax return, the Company plans to elect an available alternative which would likely result in the Company experiencing a limitation that subjects existing tax attributes at emergence to an IRC Section 382 limitation that could result in some or all of the remaining net operating loss carryforwards expiring unused. However, the Company will continue to evaluate the remaining available alternative which would not subject existing tax attributes to an IRC Section 382 limitation.

Limitations imposed on our ability to use NOLs to offset future taxable income may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitations were not in effect and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. Similar rules and limitations may apply for state income tax purposes.

Please see “Note 2—Chapter 11 reorganization” in Item 1. Financial Statements of this report for a discussion of our default upon senior securities.

None.

The exhibits listed below in the Exhibit Index, following the Signatures page, are filed, furnished or incorporated by reference pursuant to the requirements of Item 601 of Regulation S-K.

 

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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 15, 2017

 

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EXHIBIT INDEX

 

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