UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

For the quarterly period ended September 30, 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  ☐

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 November 14, 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 Part II, Item 1A. Risk Factors, our Quarterly Reports on Form 10-Q for the quarters ended March 31 and June 30, 2017, and Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2016, the factors include:

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Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions may change the schedule of any future production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.

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)

 

 ____________________________________________________________

* Item not disclosed. See “Note 2—Earnings per share.”

 

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—continued

(Unaudited)

 

____________________________________________________________

* Item not disclosed. See “Note 2—Earnings per share.”

 

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)

(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 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, except per share amounts)

 

 

 

 

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 and including March 21, 2017. As discussed in “Note 3—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 September 30, 2017 (Successor), the three months ended September 30, 2017 (Successor), and 2016 (Predecessor), the periods of March 22, 2017, through September 30, 2017 (Successor) and January 1, 2017, through March 21, 2017 (Predecessor), and the nine months ended September 30, 2016 (Predecessor), 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 three months ended September 30, 2017 and the periods of March 22, 2017, through September 30, 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 September 30, 2017, cash with a recorded balance totaling approximately $17,956 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 December 31, 2016, we had restricted cash of $1,400 which was required to be maintained during the pendency of our bankruptcy. The restricted cash is included in “Cash and cash equivalents” in our consolidated balance sheets. As of September 30, 2017, we no longer had restricted cash.

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:

 

 

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

Inventories

Inventories consisted of the following:

 

 

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 impairment has occurred. In assessing whether impairment has occurred, we consider factors such as intent to drill; remaining lease term; geological and geophysical evaluations; drilling results and activity; assignment of proved reserves; and economic viability of development if proved reserves are assigned. Upon determination of impairment, all or a portion of the associated leasehold costs are transferred to the full cost pool and become subject to amortization. The processes above are applied to unevaluated oil and natural gas properties on an individual basis or as a group if properties are individually insignificant. Our future depreciation, depletion and amortization rate would increase if costs are transferred to the amortization base without any associated reserves.

In the past, the costs associated with unevaluated properties typically related to acquisition costs of unproved acreage. As a result of fresh start accounting, a substantial portion of the carrying value of our unevaluated properties are the result of a fair value increase to reflect the value of our acreage in our STACK play (see “Note 4—Fresh start accounting”).

The costs of unevaluated oil and natural gas properties consisted of the following:

 

________________________________

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 September 30, 2017, and the related PV-10 value, 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 4—Fresh start accounting,” the application of fresh start accounting to our balance sheet on March 21, 2017, resulted in the carrying value of our oil and natural gas properties being restated based on their fair value.

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.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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 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 were 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 September 30, 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 our 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 our 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 September 30, 2017, and December 31, 2016.

As described in “Note 3—Chapter 11 reorganization,” elements of the Reorganization Plan provided that our indebtedness related to Senior Notes and certain general unsecured claims were exchanged for 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 CODI on our tax attributes. Upon filing our 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.

Joint Venture

On September 25, 2017, we entered into a drilling joint venture with BCE Roadrunner LLC, a wholly-owned subsidiary of Bayou City Energy Management, LLC (“BCE”) to fund further development of our 110,000-acre STACK position, which will allow us to accelerate our development plans in both Canadian and Garfield counties, Oklahoma. Under the Joint Development Agreement (“JDA”), BCE will fund 100 percent of our drilling, completion and equipping costs associated with 30 joint venture STACK wells, subject to average well cost caps that vary by well-type across location and targeted formations, approximately between $3,400 and $4,000 per gross well. The JDA wells, which will be drilled and operated by us, include 17 wells in Canadian County and 13 wells in Garfield County. We have the ability to expand the partnership to drill additional wells in the future. In exchange for funding, BCE will receive wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retain 15%) until the program reaches a 14% internal rate of return. Once achieved, ownership interest in all wells will revert such that we will own a 75% working interest and BCE will retain a 25% working interest. We will retain all acreage and reserves outside of the wellbore, with both parties paying their working interest share of lease operating expenses.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

Liability management

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

Cost reduction initiatives

Cost reduction initiatives include expenses related to our efforts to reduce our capital, operating and administrative costs in response to 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 May 2017, the FASB issued authoritative guidance which provides clarification on determining which changes to the terms and conditions of share-based payment awards require an entity to apply modification accounting. The guidance is effective for fiscal years, including interim periods within those annual periods, beginning after December 15, 2017, with early adoption permitted in any interim period. The guidance should be applied prospectively to an award modified on or after the adoption date. We adopted this guidance on July 1, 2017, with no material impact to our financial statements or results of operations.

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

In March 2016, the FASB issued authoritative guidance that clarifies that the assessment of whether an embedded contingent put or call option in a financial instrument is clearly and closely related to the debt host requires only an analysis of the four-step decision sequence described in Accounting Standards Codification (“ASC”) Topic 815, Derivatives and Hedging (“ASC 815”). We adopted this guidance, which was effective for fiscal periods beginning after December 15, 2016, and interim periods thereafter, in 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 3—Chapter 11 reorganization” and “Note 6—Debt”, there were no additional required disclosures as contemplated by this guidance.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

Recently issued accounting pronouncements

In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. The updated guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within that reporting period and it will be adopted by us on January 1, 2018. 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 principal vs. agent considerations and identifying performance obligations and licensing. We have completed an assessment of our marketing contracts covering a majority portion of our revenue. Based on this assessment, we do not expect the new guidance to have a material impact on prior and future net income. However, we expect the guidance to impact our classification of certain costs for gathering, transportation and processing of gas as part of the transaction price rather than reported expense. Accordingly, we are continuing to evaluate the effect that the new guidance will have on our consolidated financial statements and related disclosures, with a more focused analysis on these expenses.

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 to offset potential losses such as netting past due amounts against revenue and assuming title to the working interest, we do not expect this guidance to materially impact our financial statements or results of operations.

In 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.

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.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

Note 2: Earnings per share

We have not historically presented earnings per share (“EPS”) because our common stock did not previously trade on a public market, either on a stock exchange or in the over-the-counter (“OTC”) market. Accordingly, we were permitted under accounting guidance to omit such disclosure. However, the OTCQB tier of the OTC Markets Group Inc. began quoting our Class A common stock on May 26, 2017, under the symbol “CHPE”. From May 18, 2017, through May 25, 2017, our Class A common stock was quoted on the OTC Pink marketplace under the symbol “CHHP”. Our Class B common stock is not listed or quoted on the OTCQB or any other stock exchange or quotation system. Our Class A and Class B common stock shares equally in dividends and undistributed earnings. We are presenting basic and diluted EPS for all Successor periods subsequent to our emergence from bankruptcy but are not presenting EPS for any Predecessor period.

We are required under accounting guidance to compute EPS using the two-class method which considers multiple classes of common stock and participating securities. All securities that meet the definition of a participating security are to be included in the computation of basic EPS under the two-class method. Our unvested restricted stock awards are considered to be participating securities as they include non-forfeitable dividend rights in the event a dividend is paid on our common stock. Our participating securities do not participate in undistributed net losses because they are not contractually obligated to do so and hence are not included in the computation of EPS in periods when a net loss occurs.

A reconciliation of the components of basic and diluted EPS is presented below:

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Note 3: 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,

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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 our Senior Notes (collectively, the “Noteholders”), the following transactions occurred on or around the Effective Date:

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

Liabilities subject to compromise. In accordance with ASC Topic 852, Reorganizations (“ASC 852”), 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. As part of the Reorganization Plan, the Bankruptcy Court approved the settlement of these claims and they were subsequently settled in cash or equity, reinstated or otherwise reserved for at emergence.

 

Note 4: 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 ASC Topic 205, Presentation of Financial Statements (“ASC 205”). ASC 205 states that 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.

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

____________________________________________________________

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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.

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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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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, except per share amounts)

 

Reorganization adjustments

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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, except per share amounts)

 

Note 5: Supplemental disclosures to the consolidated statements of cash flows

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

 

 

Note 6: Debt

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

 

Prior to our emergence from bankruptcy, our debt primarily consisted of the Prior Credit Facility and our Senior Notes. On the Effective Date, our obligations under the Senior Notes which included principal and accrued interest, and previously classified as liabilities subject to compromise, 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.

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

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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 September 30, 2017, our outstanding borrowings were accruing interest at the Adjusted LIBO Rate which resulted in an interest rate of 9.03%.

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 September 30, 2017, after taking into account outstanding borrowings and letters of credit on that date, was $71,172.

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 September 30, 2017, our outstanding borrowings were accruing interest at the Adjusted LIBO Rate which resulted in a weighted average interest rate of 4.78%.

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 of 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 as of January 1 and July 1 of each year. We were in compliance with these financials covenants as of September 30, 2017.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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.

Note 7: 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 September 30, 2017:

The following table summarizes our natural gas derivatives outstanding as of September 30, 2017:

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

Effect of derivative instruments on the consolidated balance sheets

All derivative financial instruments are recorded on the balance sheet at fair value. See “Note 8—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:

 

Derivative terminations

In May 2016 all of our outstanding derivative positions were terminated due to defaults under the master agreements governing our derivative contracts as a result of our bankruptcy. Proceeds from the early terminations, inclusive of amounts receivable at the time of termination for previous settlements, totaled $119,303. Of this amount, in the third quarter of 2016, $103,560 was utilized to offset outstanding borrowings under our Prior Credit Facility and the remainder was remitted to the Company.

Note 8: Fair value measurements

Fair value is defined by the FASB as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

Fair value measurements are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities as follows:

In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the asset or liability is categorized based on the lowest level input that is significant to the fair value measurement in its entirety. Our assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

Recurring fair value measurements

As of September 30, 2017, and December 31, 2016, our financial instruments recorded at fair value on a recurring basis consisted of commodity derivative contracts (see “Note 7—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 our counterparty credit risk for derivative assets.

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

 

 

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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 nine 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 once we emerged from bankruptcy through September 30, 2017, were discounted, depending on the economic remaining estimated life of the property or the expected timing of the plugging and abandonment activity, with a credit-adjusted risk-free rate ranging from 5.13% to 7.63%. The discount rate used for the nine months ended September 30, 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 statutory remediation rules. See “Note 9—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 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.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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 September 30, 2017, the counterparties to our open derivative contracts consisted of four financial institutions.

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 September 30, 2017.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

Note 9: Asset retirement obligations

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

 

See “Note 8—Fair value measurements” for additional information regarding fair value assumptions associated with our asset retirement obligations.

Note 10: 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.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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

 

During 2017, the Company awarded an additional $5,637 under the 2015 Cash LTIP. As of September 30, 2017, the outstanding liability accrued for our 2015 Cash LTIP, based on requisite service provided, was $1,224.

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.

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

 

 

2017 Management Incentive Plan

As discussed in “Note 3—Chapter 11 reorganization,” our Reorganization Plan authorized the issuance of seven percent of outstanding Successor common shares on a fully diluted basis toward a new management incentive plan. On August 9, 2017, we adopted the Chaparral Energy, Inc. Management Incentive Plan (the “MIP”). The MIP provides for the following types of awards:

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

options, stock appreciation rights, restricted stock, restricted stock units, performance awards and other incentive awards.  The aggregate number of shares of Class A common stock, par value $0.01 per share, reserved for issuance pursuant to the MIP was initially set at 3,388,832 subject to changes in the event additional shares of common stock are issued under our Reorganization Plan. The MIP contemplates that any award granted under the plan may provide for the earlier termination of restrictions and acceleration of vesting in the event of a Change in Control, as may be described in the particular award agreement.

Pursuant to the MIP, in August 2017, 1,796,943 shares of restricted stock were granted to employees and members of our Board of Directors (the “Board”). Of the grants awarded to employees, 75% were comprised of shares that are subject to service vesting conditions (the “Time Shares”) and 25% were comprised of shares that are subject to performance vested conditions (the “Performance Shares”). All grants to the Board were Time shares.

Upon evaluating the provisions of both Time and Performance Shares, we classified both awards as equity-based awards. Compensation cost will be recognized and measured according to the grant date fair value of the awards which are based on the market price of our common stock currently trading on the OTCQB tier of the OTC Markets Group, Inc.

The Time Shares vest in equal annual installments over the three -year vesting period beginning on April 1, 2018 and each anniversary thereafter. The Performance Shares vest in three tranches over each of the next three years beginning on December 31, 2017, and each anniversary thereafter, according to performance conditions established each year. The performance conditions for a given year are unique to that year and vesting with respect to performance conditions for a given year is independent of the vesting with respect to other years. As a result, the requisite service period for each of the three tranches of Performance Shares relate to the individual year for which performance is measured and do not overlap.  Performance conditions have not been established for 2018 and 2019 and hence a grant date has not been established for accounting purposes. Furthermore, since the requisite service period for Performance Shares related to 2018 and 2019 performance conditions will not commence until fiscal 2018 and 2019, no expense will be recognized in connection with those awards in 2017. Performance Shares related to 2017 performance conditions will vest based on accomplishment of multiple conditions that generally relate to drilling results and strategic goals. The accomplishment of an individual condition will result in vesting of shares that is independent of vesting with respect to the other conditions (i.e. simultaneous accomplishment of multiple conditions is not required for vesting).  The number of shares vesting with respect to certain 2017 performance conditions is primarily at the discretion of the Board; hence a grant date for the related shares has not been established for accounting purposes.  Requisite service on Performance Shares subject to these discretionary 2017 performance conditions is being rendered in 2017 and therefore expense is recognized in the current fiscal year.

A summary of our restricted stock activity pursuant to our MIP for the Successor period in 2017 is presented below:

________________________________________________________

As none of the MIP awards have vested to date, there have been no repurchases of vested shares in 2017. We have the ability to repurchase shares for tax withholding or pursuant to certain share repurchase provisions in our MIP award agreements. However, our employees also have the ability to sell shares on the open market to cover employee tax withholdings.

Stock-based compensation cost

Compensation cost is calculated net of forfeitures. As allowed by recent accounting guidance, we will recognize the impact of forfeitures due to employee terminations on expense as they occur instead of incorporating an estimate of such forfeitures. For awards with performance conditions, we will assess the probability that a performance condition will be achieved at each reporting period to determine whether and when to recognize compensation cost.

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Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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. Stock-based compensation expense is as follows for the periods indicated:

 

The credit for stock-based compensation for the nine months ended September 30, 2016, was primarily a result of forfeitures from our workforce reduction in January 2016, lower valuations of our liability-based awards and the cumulative catch up adjustment on the 2010 Plan discussed above. Based on a quarter end market price of $23.25 per share of our common stock, the aggregate intrinsic value of all restricted shares outstanding was $41,779 as of September 30, 2017. As of September 30, 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. Unrecognized stock-based compensation cost of approximately $25,805 as of September 30, 2017, is expected to be recognized over a weighted-average period of 1.5 years.

 

Note 11: Commitments and contingencies

Standby letters of credit (“Letters”) available under our New 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 September 30, 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 New Credit Facility. No amounts were paid by the lenders under the Letters; therefore, we paid no interest on the Letters during the nine months ended September 30, 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 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 or, if the amount is such claim is below the convenience class threshold, through cash settlement.

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

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Case”). Plaintiffs indicated they seek damages in excess of $5,000, the majority of which would be comprised of interest and may increase with the passage of time. 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. On May 20, 2016, we filed a Notice of Suggestion of Bankruptcy with the Naylor Trial Court.

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. After additional briefing on the subject, on April 18, 2017, the Naylor Trial Court issued an order certifying the class to include only claims relating back to June 1, 2006. On May 1, 2017, we filed a Petition for Permission to Appeal Class Certification Order with the Tenth Circuit Court of Appeals (the “Tenth Circuit”), which was granted. We filed our appellate brief on September 14, 2017, to which the plaintiffs must respond by November 16, 2017.

In addition to filing claims on behalf of the named plaintiffs and associated parties, on August 15, 2016, plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming damages in excess of $150,000 in our Chapter 11 Cases. The Company objected to treatment of the claim on a class basis, asserting the claim should be addressed on an individual basis. On April 20, 2017, plaintiffs filed an amended proof of claim reducing the claim to an amount in excess of $90,000 inclusive of actual and punitive damages, statutory interest and attorney fees. On May 24, 2017, the Bankruptcy Court denied the Company’s objection, ruling the plaintiffs may file a claim on behalf of the class. This order did not establish liability or otherwise address the merits of the plaintiffs’ claims, to which we will also object. On June 7, 2017 we appealed the Bankruptcy Court order to the United States District Court for the District of Delaware. Under the Reorganization Plan, the plaintiffs are identified as a separate class of creditors, Class 8. 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 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 includes 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 included non-governmental royalty interest owners in oil and natural gas wells we operate in Oklahoma. We responded to the Dodson petition, denied the allegations and raised a number of affirmative defenses. The case was voluntarily dismissed without prejudice on July 19, 2017.

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 Policy Act (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 all defendants as an improper challenge under NEPA and the Administrative Procedures Act. On April 29, 2016, the plaintiffs filed motions to alter or amend the court’s opinion and vacate the judgment, and to file an amended complaint to cure the deficiencies which the court found in the dismissed complaint. On May 20, 2016, the Company filed a Notice of Suggestion of Bankruptcy, and as a result have not responded to the plaintiffs’ motions. After plaintiff’s motion for reconsideration was denied, plaintiffs filed a Notice of Appeal on December 6, 2016. The Court has not ruled on the appeal, and has scheduled oral arguments for November 14, 2017.

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.

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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

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 earthquakes in the Class Area. The plaintiffs did not seek damages for property damage, instead asked the court to require the defendants to reimburse plaintiffs and class members for earthquake insurance premiums from 2011 through the time at which the court determines there is no longer a risk of induced earthquakes, as well as attorney fees and costs and other relief. We responded to the petition, denied the allegations and raised a number of affirmative defenses. 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. Other defendants filed motions to dismiss the action which was granted on May 12, 2017. On July 18, 2017, plaintiffs filed a Second Amended Complaint adding additional named plaintiffs as putative class representatives and adding three additional counties to the putative class area. In the Second Amended Complaint, plaintiffs seek damages for nuisance, negligence, abnormally dangerous activities, and trespass. Due to Chaparral’s bankruptcy, plaintiffs specifically limit alleged damages related to Chaparral’s disposal activities occurring after our emergence from bankruptcy on March 21, 2017. We moved to dismiss the Second Amended Complaint on September 15, 2017.

Plaintiffs’ attorneys filed a proof of claim on behalf of the putative class claiming in excess of $75,000 in our Chapter 11 Cases. We filed an objection to class treatment of the proof of claim filed by the West plaintiffs in our Bankruptcy proceeding. The Bankruptcy Court had a hearing on our objection, but has not yet ruled. 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.

Lisa Griggs and April Marler, on behalf of themselves and other Oklahoma citizens similarly situated v. New Dominion, L.L.C. et al. On July 21, 2017, an alleged class action was filed against us and other operators, in the District Court of Logan County, State of Oklahoma. The named plaintiffs assert claims on behalf of themselves and Oklahoma citizens owning a home or business between March 30, 2014, and the present in a Class Area which encompasses nine counties in central Oklahoma. The plaintiffs allege disposal of saltwater produced during oil and gas operations induced earthquakes in the Class Area, and each defendant has liability under theories of ultra-hazardous activities, negligence, nuisance, and trespass. On October 24, 2017, plaintiffs filed a First Amended Class Petition in Logan County, Oklahoma, adding Creek County, Oklahoma to the Class Area, and adding an additional earthquake to the list of seismic events allegedly caused by the defendants. The plaintiffs have asked the court to award unspecified damages for damage to real and personal property and loss of market value, loss of use and enjoyment of the properties, and emotional harm, as well as punitive damages and pre-judgment and post-judgment interest. We will 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 vigorously defend the case.

We dispute the plaintiffs’ claims, dispute that the case meets the requirements for a class action, dispute the plaintiffs are entitled to recovery under our Reorganization Plan, and are vigorously defending the case.

James Butler et al. v. Berexco, L.L.C., Chaparral Energy, L.L.C, et al.  On October 13, 2017, a group of fifty-two individual plaintiffs filed a lawsuit in the District Court of Payne County, State of Oklahoma against twenty six named defendants, including us, and twenty five unnamed defendants. Plaintiffs are all property owners and residents of Payne County, Oklahoma, and allege salt water disposal activities by the defendants, owners or operators of salt water disposal wells, induced earthquakes which have caused damage to real and personal property, and emotional damages. Plaintiffs claim absolute liability for ultra-hazardous activities, negligence, gross negligence, public and private nuisance, trespass, and ask for compensatory and punitive damages. In addition to disputing the plaintiffs’ claims, we will dispute the remedies requested are available under Oklahoma law, and vigorously defend 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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Chaparral Energy, Inc. and subsidiaries

Condensed notes to consolidated financial statements (unaudited) – continued

(dollars in thousands, except per share amounts)

 

obligations primarily relate to a contract for the purchase of CO₂ and drilling rig services. Other than changes to our credit facilities (see “Note 6—Debt”) and the discharge of our Senior Notes and certain general unsecured claims pursuant to our Reorganization Plan (see “Note 3—Chapter 11 reorganization”), there were no material changes to our contractual commitments since December 31, 2016.

 

Note 12: Subsequent events

On October 13, 2017, we entered into a purchase and sale agreement with Perdure Petroleum, LLC., for the sale of our EOR assets along with some minor assets within geographic proximity for total cash consideration, subject to normal and customary closing adjustments, of $170,000 plus certain contingent payments. An $11,900 performance deposit was received in October 2017 and will be applied towards the purchase price at closing, which we expect to occur in November 2017. The effective date of the purchase is June 1, 2017.

 

 

 

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The following discussion and analysis is intended to assist in understanding our financial condition and results of operations for the three months ended September 30, 2017 (Successor), and 2016 (Predecessor), the periods of March 22, 2017, through September 30, 2017 (Successor) and January 1, 2017, through March 21, 2017 (Predecessor), and the nine months ended September 30, 2016 (Predecessor). The information should be read in conjunction with our unaudited consolidated financial statements and the notes thereto included in this quarterly report as well as the information included in our Annual Report on Form 10-K for the fiscal year ended December 31, 2016, 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" relate to the financial position and results of operations of the reorganized company subsequent to March 21, 2017. References to "Predecessor" 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. Through September 30, 2017, a significant portion of our production was derived 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. However, we have entered into an agreement to sell all our EOR related assets, which we expect to close in November 2017.

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.

Based on our September 30, 2017, reserve estimates according to SEC criteria, excluding properties we have sold or plan to sell such as the expected sale of our EOR assets, we estimate that our production rate on current proved developed properties will decline at annual rates of approximately 20%, 15%, and 12% 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:

Highlights

The following are events in 2017 that had or will have a material impact on our financial results or operations:

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Our financial and operating performance, outside of transactions related to our emergence from bankruptcy, in the third quarter of 2017 includes the following highlights:

Our emergence from bankruptcy and the resulting adoption of fresh start accounting had a material impact on our consolidated statement of operations mainly due to a $642 million increase in carrying value of our net assets restated to fair value pursuant to the adoption of fresh-start accounting combined with the $372 million gain on settlement of liabilities subject to compromise, both recognized during the Predecessor period in 2017. Significant increases in carrying value of our assets in connection with fresh-start accounting included the following:

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

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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 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 occurred on or around 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.

Joint development agreement

On September 25, 2017, we entered into a joint development agreement with BCE to fund further development of our 110,000-acre STACK position, which will allow us to accelerate our development plans in both Canadian and Garfield counties. Under the JDA, BCE will fund 100 percent of our drilling, completion and equipping costs associated with 30 joint venture STACK wells, subject to average well cost caps that vary by well-type across location and targeted formations, approximately between $3.4 million to $4.0 million per gross well. The JDA wells, which will be drilled and operated by us, include 17 wells in Canadian County and 13 wells in Garfield County, with the ability to expand the JDA to drill additional wells in the future. In exchange for funding, BCE will receive wellbore-only interest in each well totaling an 85% carve-out working interest from our original working interest (and we retain 15%) until the program reaches a 14% internal rate of return. Once achieved, ownership interest in all wells will revert such that we will own a 75% working interest and BCE will retain a 25% working interest. We will retain all acreage and reserves outside of the wellbore, with both parties paying their respective share of lease operating expenses. Since inception of the JDA, we have drilled three wells and are in the process of drilling the fourth under this program.

EOR sale

On October 13, 2017, we entered into a purchase and sale agreement with Perdure Petroleum, LLC, for the sale of our EOR assets along with some minor assets within geographic proximity for total consideration of $170 million in cash plus certain contingent payments and subject to normal and customary closing adjustments. The sale is expected to close in November 2017 and we have received an $11.9 million performance deposit to be applied towards the purchase price at closing. The effective date of the purchase is June 1, 2017. We expect selling costs, primarily for commissions, to be approximately $1.5 million. We also expect to incur severance costs of approximately $3.0 million for employees terminated in conjunction with the sale.

The assets included in the anticipated sale contributed approximately 5,700 boe/day of net production during the third quarter of 2017 and comprise 51% of our proved oil and natural gas reserves based on SEC criteria as of September 30, 2017. The sale of these assets marks a major milestone in the transition of the company to becoming pure-play STACK operator. The impact of this sale on our liquidity is discussed below in Liquidity and Capital Resources.

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 and by hedging a substantial portion of our expected future oil and natural gas production.

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. 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 subsequent to fresh start application as well as the increase in SEC average prices resulted in

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carrying values that were below the full cost ceiling at the end of the first, second and third quarters of 2017 and thus ceiling test write-downs were not required during the first nine months of 2017.

In addition to commodity prices, our production rates, levels of proved reserves, estimated future operating expenses, estimated future development costs, estimated fair value of unevaluated properties, transfers of unevaluated properties and other factors will determine our actual ceiling test calculation and impairment analyses in future periods.

Capital development

We incurred capital expenditures of $37.3 million and $127.9 million for the periods from January 1 to March 21 and from March 22 to September 30, 2017, respectively. This included expenditure for completing two wells drilled in the previous year, drilling and completing 17 wells, drilling six wells to be completed in the fourth quarter of 2017 and participating in outside operated wells, all within our STACK play. In addition to the activity described above, under our JDA, we have drilled three wells and are in the process of drilling the fourth, all of which were fully funded by BCE, our JDA partner. 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. We increased our 2017 capital budget, previously set at $145.9 million, to a range of $185 million to $200 million due to increased activity in our STACK play. The increased capital budget is a result of the success of our operated drilling program where we will increase the number of operated wells drilled, increased activity from other STACK operators resulting in an increase of our outside operated drilling and completion expenditures and cost inflationary pressures. In addition, we have expanded our leasehold acquisition budget as we have been successful in acquiring STACK acreage in our core operating areas at attractive prices. We plan to fund our capital budget with a combination of cash flows from operations, borrowings under our New Credit Facility and proceeds from recent and expected future sales of non-core assets of approximately $25 million to $30 million.

Trading of common stock

On May 26, 2017, the OTCQB tier of the OTC Markets Group, Inc. began quoting our Class A common stock under the symbol “CHPE”. From May 18, 2017 through May 25, 2017, our Class A common stock was quoted on the OTC Pink marketplace under the symbol “CHHP”. No established public trading market existed for our Class A common stock prior to that date. Our Class B common stock is not listed or quoted on the OTCQB or any other stock exchange or quotation system, and we have not applied for such listing. Although our Class A common stock is quoted on the OTCQB, trading and quotations on the stock have been limited and sporadic.

Results of operations

Production

Production volumes by area were as follows:

 

 

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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. Our primary focus recently has been in our STACK Areas where we have directed the majority of our capital expenditures and where of our strategy is to transition to be a pure-play STACK operator. 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.

Production increased for the three months ended September 30, 2017, compared to the prior year primarily due to production increases in our STACK Area. Production in our STACK play increased as a result of increased capital spending throughout this area with a result of 19 operated wells that came online during the period and our participation in new outside-operated wells in this play.  Production in our Active EOR Area was flat as decreases in our Farnsworth and Camrick units were partially mitigated by an increase at the North Burbank Unit. Production decreased in our Other Areas due to natural decline.

Our total net production for the nine months ended September 30, 2017, which was comprised of 4,662 MBoe for the Successor period and 1,796 MBoe for the Predecessor period, declined from the prior year period primarily due to production declines in all our areas outside the STACK. Areas outside the STACK, other than our Active EOR North Burbank and Booker units, experienced declining production due to a decrease in development activity.  In addition, a severe ice storm in the Oklahoma Panhandle in early 2017 had an adverse impact on our oil production in our Active EOR and Other areas.  As mentioned above, production in our STACK play and North Burbank Unit increased as a result of our continued capital development throughout 2017.

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:

 

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Our commodity sales for the quarter ended September 30, 2017, were higher than the prior year quarter, due to price and production increases on oil and natural gas liquids partially offset by price and production decreases in natural gas. Our total commodity sales for the period from January 1 - March 21 and March 22 - September 30, 2017 were higher than the prior year period due to price increases offset partially by production decreases on all commodities 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 portion of this exposure, we have entered into various types of derivative instruments, including commodity price swaps and costless collars.

Due to defaults under our derivative master agreements stemming from our bankruptcy, our outstanding derivative positions were terminated in May 2016. Proceeds from the early terminations, inclusive of amounts receivable for previous settlements, totaled $119.3 million of which $103.6 million was utilized to offset outstanding borrowings under our Prior Credit Facility and the remainder was remitted to the Company during the third quarter of 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.

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Our realized prices are impacted by realized gains and losses resulting from commodity derivatives contracts. The table below presents information about the effects of derivative settlements on realized prices during 2017. We have not presented comparative information for the 2016 periods as such information is not meaningful due to the effect of early terminations of outstanding contracts discussed above.

 

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 expenses (“LOE”)  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.

LOE is not comparable across the time periods presented above in part due to our recognition of bonus expense. 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. We resumed accruing bonuses in the ordinary course of business during the second quarter of 2017. The bonus expense component of lease operating expense is disclosed in the table below:

 

LOE for the three months ended September 30, 2017 of $24.2 million were higher compared to the prior year quarter primarily due to new operated and outside-operated wells that came online in our STACK area during the period, as well as an overall increase in costs, partially offset by decrease in LOE as a result of shutting-in of higher cost underperforming wells. LOE increased on a per Boe basis for the three months ended September 30, 2017 compared to the prior year quarter primarily as a result of the effects of increasing industry-wide pricing for certain oilfield services, primarily water hauling and disposal. While many costs remain at low levels, certain costs have risen as industry drilling activity continues to recover and expand.

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LOE for the nine months ended September 30, 2017, which were comprised of $51.5 million and $19.9 million for the Successor and Predecessor periods, respectively, increased from the prior year period primarily due to the bonuses accrued and paid this year.  Absent the accrual for bonuses, our overall LOE would have been relatively flat. Increases in our STACK play were due to new operated and outside-operated wells that came online, and were partially offset by decreases in the Active EOR and Other areas, largely due to the shut in of higher cost underperforming wells.

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 expenses of $2.9 million for the three months ended September 30, 2017, were higher compared to the three months ended September 30, 2016, as a result of both increased gas volumes and a larger proportion of our gas production attributable to our STACK area where we have experienced higher transportation and processing costs compared to our Other operating areas. In addition, we are also experiencing higher per unit costs associated with our non-operated wells and a larger proportion of gas production subject to fee based processing arrangements as opposed to percentage of proceeds (“POP”) arrangements.  These factors also similarly impacted our expenses for the nine months ended September 30, 2017, comprised of $6.4 million and $2.0 million for the Successor and Predecessor periods, which were higher compared to the nine months ended September 30, 2016.

As discussed  in “Note 1—Nature of operations and summary of significant accounting policies” in Item 1. Financial Statements of this report, we anticipate that our adoption in 2018 of new accounting guidance on revenue recognition will result in substantially all of our transportation and handling expenses being recorded as revenue deductions rather than as expenses in our statement of operations.

Production taxes (which include severance and valorem taxes)

 

 

In May 2017, the Oklahoma legislature passed bills that would effectively increase production taxes on certain producing wells and units in the state. The bills end all production tax rebates for EOR operations and increases the rate on horizontal wells spudded on or prior to July 1, 2015. These bills, which took effect in July 2017, resulted in an additional $0.5 million increase in production taxes related to production in our Active EOR Areas and $0.3 million increase on our horizontal well production for the three months ended September 30, 2017.

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Production taxes on a dollar and per Boe basis for the three months ended September 30, 2017, and in aggregate for the periods from January 1 – March 21 and March 22 – September 30, 2017, were higher than the comparable periods in 2016 as a result of increased revenues from higher commodity prices and the legislative changes discussed above.

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

 

We adjust our DD&A rate on oil and natural gas properties each quarter for 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 emergence from bankruptcy whereupon the carrying value of our proved oil and gas properties and tangible property on our balance sheet was restated to fair value. The restatement resulted in an increase in the full cost amortization base which impacted the DD&A rate per equivalent unit of production for the period subsequent to March 21, 2017. Notwithstanding a lack of comparability, overall oil and natural gas DD&A was also impacted by production differences. Production increased for the three months ended September 30, 2017, compared to the prior year quarter resulting in an increase in DD&A over the comparable periods. However, year over year production decreased which resulted in a decrease in DD&A between the Successor and Predecessor periods in 2017 compared to the nine months ended September 30, 2016. Upon the sale our EOR assets, we expect our DD&A rate to be lower than the current rate largely because our amortization base will no longer be burdened by the high future development costs associated with our EOR reserves.

Asset impairments

 

 

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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 adjustments for activity subsequent to fresh start application as well as the increase in SEC average prices resulted in carrying values that were below the full cost ceiling at the end of the first, second and third quarters of 2017 and thus ceiling test write-downs were not required during the first nine months of 2017.

During 2016, we incurred ceiling test impairments on our oil and natural gas assets of $281.1 million while the impairment losses on other assets were due to lower of cost or market adjustments on our equipment inventory.

General and administrative expenses (“G&A”)

 

 

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Gross G&A expense for the three months ended September 30, 2017, of $12.7 million, was higher than the prior year quarter primarily due to the following:

Gross G&A expense of $30.8 million and $8.1 million for the periods from March 22 – September 30 and January 1 – March 21, 2017, respectively, was higher in total compared to the prior year period primarily due to the equity compensation, bonus expense, professional fee and LTIP transactions described above. Other than the factors discussed above, professional fees were also higher in the current year due to costs associated with the preparation and filing of the Registration Statement during the second quarter of 2017.

As discussed above, G&A expense is impacted by a Performance Vested stock adjustment in 2016 and the timing of our recognition of bonus expense, both of which materially impacted comparability across the periods presented. A cumulative catch up adjustment was recorded during the third quarter of 2016 to reverse the aggregate compensation cost associated with our Performance Vested restricted stock awards in order to reflect a decrease in the probability that that requisite service would be achieved for these awards in light of our bankruptcy at that time. 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. We resumed bonus accrual in the ordinary course of business beginning in the second quarter of 2017. These adjustments are disclosed in the table below:

Capitalized exploration and development costs were higher in the three months ended September 30, 2017 compared to the three months ended September 30, 2016 due to capitalized costs on the newly implemented management incentive program and the impact of the Performance Vested stock adjustment in the prior year. Total capitalized exploration and development costs of $6.2 million and $1.3 million for the periods from March 22 - September 30 and January 1 – March 21, 2017, respectively, increased compared to the

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nine months ended September 30, 2016, primarily due to current year capitalized costs on the newly implemented management incentive program and the bonus adjustment as well as the prior year impact of the Performance Vested stock adjustment.

Cost reduction initiatives

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 and therefore substantially all our expenses are from one-time severance and termination benefits in connection with the layoffs.

Liability management expenses

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 were 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 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 three months ended September 30, 2017 and from March 22 to September 30, 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, and the three months ended September 30, 2016, 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 nine months ended September 30, 2016, we incurred interest related to our Senior Notes and Prior Credit Facility.

Interest expense in 2017 which included $5.3 million, $11.0 million and $5.9 million for three months ended September 30, 2017, the period from March 22 – September 30, 2017 and the period from January 1 – March 21, 2017, respectively, was lower than comparable periods in 2016 primarily due to lower debt balances and the absence of interest expense on the Senior Notes in the

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current year period. Capitalized interest increased during the three months ended September 30, 2017, compared to the prior year quarter as a result of a higher carrying amount of unevaluated purchased non-producing leasehold from our acreage acquisitions.. 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.

Reorganization items

Reorganization items reflect, where applicable, 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 4—Fresh start accounting” in Item 1. Financial Statements of this report. Our reorganization items are presented below (in thousands):

 

 

Liquidity and capital resources

Upon emergence from bankruptcy, our primary sources of liquidity have been cash flows from operations, borrowings under our New Credit Facility and proceeds from derivative settlements. Other potential sources of liquidity in the future include sales of non-core assets and equity offerings. 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. Our cash balance as of September 30, 2017, was $22.4 million and we had borrowing availability under our New Revolver of $71.2 million. As of November 10, 2017, our cash balance was approximately $21.4 million with $153.0 million outstanding on our New Revolver and borrowing availability of $71.2 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).

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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 nine months ended September 30, 2017, which included inflows of $38.2 million for Successor period and $14.4 million for the Predecessor period, increased over the prior year as a result of an increase in revenues and lower interest payments in the current year coupled with working capital changes. These increases were partially offset by higher lease operating, general and administrative, and bankruptcy related costs in the current year.

When available, we use the net cash provided by operations to partially fund our acquisition, exploration and development activities. Due to low commodity prices, we also received cash from settlement of our derivative contracts as well as utilizing borrowings under our New Revolver and cash on hand to help fund our capital expenditures in 2017.

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 nine months ended September 30, 2017, and our budgeted 2017 capital expenditures for oil and natural gas properties are summarized in the table below.

 

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We previously increased our 2017 capital budget, previously set at $145.9 million, to a range of $185 million to $200 million due to increased activity in our STACK play. The increased capital budget is a result of the success of our operated drilling program where we will increase the number of operated wells drilled, increased activity from other STACK operators resulting in an increase of our outside operated drilling and completion expenditures and cost inflationary pressures. In addition, we have expanded our leasehold acquisition budget as we have been successful in acquiring STACK acreage in our core operating areas at attractive prices and we have taken advantage of that opportunity. We plan to fund our capital budget with a combination of cash flows from operations, borrowings under our New Credit Facility and proceeds from recent and expected future sales of non-core assets of approximately $25 million to $30 million.

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Net cash used in investing activities during the Successor period from March 22 – September 30, 2017 was comprised of cash outflows for capital expenditure of $114.4 million partially offset by cash inflows from derivative settlement receipts of $15.1 million and from asset sales of $7.8 million. Net cash used in investing activities during the Predecessor period from January 1 to March 21, 2017, was comprised of cash outflows for capital expenditure of $31.2 million partially offset by cash inflows from derivative settlement receipts of $1.3 million and from asset sales of $1.9 million. Net cash used investing activities during the nine months ended September 30, 2016, of the Predecessor, was comprised primarily of cash outflows for capital expenditure of $120.0 million partially offset by cash inflows from derivative settlement receipts of $90.6 million and from asset sales of $1.0 million.

Cash flows from financing activities during the Successor period from March 22 to September 30, 2017, is comprised primarily of cash inflows of $33.0 million from borrowings under our New Revolver partially offset by repayments of $2.5 million on debt and capital leases. Cash flows used in financing activities during the Predecessor period from January 1 to March 21, 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 and $50.0 million from the issuance of equity. The large repayments and borrowings of debt during the Predecessor period in 2017 reflect the extinguishment of our Prior Credit Facility and establishment of our New Credit Facility pursuant to our Reorganization Plan. Cash flows from financing activities during the six months ended September 30, 2016 included borrowings of $181.0 million on our debt and repayments of $3.4 million on our debt and 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 $2.4 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. Upon the anticipated closing of the EOR asset sale in November 2017, we intend to repay in full the oustanding balance on our New Term Loan. The details of the EOR asset sale are discussed below.

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

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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. As discussed below, we entered into a letter agreement with the lenders under our New Credit Facility that provides that the borrowing base will remain at $225.0 million after giving effect to the anticipated consummation of the EOR asset sale.

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 contains certain thresholds on the amount of oil and gas properties that can be disposed of or commodity hedges that can be terminated within a specified timeframe before triggering mandatory prepayments. Upon the consummation of a Triggering Disposition (as defined in the New Credit Facility) the borrowing base will be automatically decreased by an amount equal to the borrowing base value assigned to the oil and gas properties disposed of. Additionally, 100% of the net proceeds received from the Triggering Disposition would be required to be used to prepay the New Term Loan minus any amounts required to cure a borrowing base deficiency from the decrease in the borrowing base. The potential impact of our EOR asset sale, which will meet the criteria as a Triggering Disposition, on the New Credit Facility is discussed below.

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 of 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. We were in compliance with our financial covenants under the New Credit Facility as of September 30, 2017.

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 were for 84-month terms and with minimum lease payments of $3.2 million annually. Upon the anticipated closing of the EOR asset sale, the compressors will be subleased to the buyer.

Potential impact of EOR asset sale

On October 13, 2017, we entered into a purchase and sale agreement for the sale of our EOR assets along with some minor assets within geographic proximity for total consideration of $170 million in cash plus certain contingent payments and subject to normal and customary closing adjustments. The sale is expected to close in November 2017. Due to the magnitude of the assets and underlying oil and natural gas reserves being conveyed, the sale will qualify as a Triggering Disposition under the terms of our New Credit Facility. Pursuant to the provisions required for a Triggering Disposition, we intend to utilize all the proceeds from the sale to repay in full the $149.2 million outstanding balance of our New Term Loan and to reduce outstanding borrowings under our New Revolver. With the anticipated payment in full on the New Term Loan, we expect interest expense in future quarters to be lower than expense in the current quarter.

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On November 7, 2017, we entered into a letter agreement with the lenders under our New Credit Facility pursuant to which the parties agreed that the EOR asset sale described above would be excluded from any determination of a Triggering Disposition or automatic reduction of the borrowing base under the New Credit Facility as would have been required under the terms of the facility. In addition, the letter agreement stipulates that the borrowing base will remain at $225.0 million after giving effect to the consummation of the EOR asset sale until the next redetermination, as provided for under the facility.

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 outstanding operating leases primarily relate to office equipment. We also have outstanding capital leases and operating leases on CO₂ recycle compressors at our EOR facilities which we intend to sublease to the buyer upon closing the sale of our EOR assets. Our outstanding purchase obligations primarily relate to contracted drilling rig services and the purchase of CO₂. Our CO2 purchase obligations will be discharged upon closing our EOR asset sale.

Other than changes to our indebtedness and general unsecured claims as a result of our Reorganization Plan, there have been no other material changes to our commitments subsequent to December 31, 2016.

Off-balance sheet arrangements

Our off-balance sheet arrangements as of September 30, 2017, include warrants to purchase 140,023 shares of Successor common stock with an exercise price of $36.78 per share and expiring on June 30, 2018. These warrants embody a contract that would have been accounted for as a derivative instrument except that they are both indexed to our own stock and classified in stockholders equity.

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:

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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. In addition, Adjusted EBITDA is generally consistent with the EBITDAX calculation that is used in the Ratio of Total Debt to EBITDAX covenant under our New Credit Facility. Adjusted EBITDA is not defined under GAAP and, accordingly, it may not be a comparable measurement to those used by other companies.

We define adjusted EBITDA as net income, adjusted to exclude (1) asset impairments, (2) interest and other financing costs, net of capitalized interest, (3) income taxes, (4) depreciation, depletion and amortization, (5) non-cash change in fair value of non-hedge derivative instruments, (6) interest income, (7) stock-based compensation expense, (8) gain or loss on disposed assets, (9) upfront premiums paid on settled derivative contracts, (10) impairment charges, (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 based on the prevailing provisions under our credit facility at that time.

The following tables provide a reconciliation of net (loss) income to adjusted EBITDA for the specified periods:

 

 

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The EBITDAX definition in our New Credit Facility requires that we give pro forma effect to any Material Disposition, as defined in New Credit Facility, as if such Material Disposition had occurred on the first day of such Reference Period (as defined). As a result of this provision, computing the Ratio of Total Debt to EBITDAX for the year to date ending December 31, 2017, may require that we exclude any EBITDAX attributable to properties from our anticipated EOR asset sale. We estimate that the amount we would exclude for the nine month period ending September 30, 2017, would be approximately $41.2 million.

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.

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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 nine months ended September 30, 2017, our gross revenues from oil and natural gas sales would change approximately $4.7 million for each $1.00 change in oil and natural gas liquid prices and $1.1 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 7—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 September 30, 2017, was a net asset of $14.1 million. Based on our outstanding derivative instruments as of September 30, 2017, summarized below, a 10% increase in the September 30, 2017, forward curves used to mark-to-market our derivative instruments would have decreased our position to a net liability of $12.1 million, while a 10% decrease would have increased our net asset position to $40.3 million.

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Our outstanding oil derivative instruments as of September 30, 2017, are summarized below:

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Our outstanding natural gas derivative instruments as of September 30, 2017, are summarized below:

Interest rates.  As of September 30, 2017, borrowings bear interest at the Adjusted LIBO 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 of $302.2 million, equal to the balance under our New Credit Facility as of September 30, 2017, the cash flow impact for a 12-month period resulting from a 100 basis point change in interest rates would be $3.0 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 September 30, 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 11—Commitments and contingencies” in Item 1. Financial Statements of this report for a discussion of our material legal proceedings. In our opinion, there are no other material pending legal proceedings to which we are a party or of which any of our property is the subject. However, due to the nature of our business, certain legal or administrative proceedings may arise from time to time in the ordinary course of business. While the outcome of these legal matters cannot be predicted with certainty, we do not expect them to have a material adverse effect on our financial condition, results of operations or cash flows.

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During 2017, there have been no material changes in our risk factors disclosed in Part I, Item 1A. Risk Factors in our Annual Report on Form 10-K for the year ended December 31, 2016, and in Part II, Item 1A. Risk Factors in our Quarterly Reports on Form 10-Q for the quarters ended March 31, 2017, and June 30, 2017.

Please see “Note 3—Chapter 11 reorganization” in Item 1. Financial Statements of this report for a discussion of our default upon senior securities.

None.

 

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SIGNATURES

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

 

 

Date: November 14, 2017

 

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