Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2018 | May 09, 2018 | |
Entity Information [Line Items] | ||
Entity Registrant Name | Chaparral Energy, Inc. | |
Entity Central Index Key | 1,346,980 | |
Current Fiscal Year End Date | --12-31 | |
Entity Filer Category | Non-accelerated Filer | |
Document Type | 10-Q | |
Document Period End Date | Mar. 31, 2018 | |
Trading Symbol | CHPE | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q1 | |
Amendment Flag | false | |
Common Class A | ||
Entity Information [Line Items] | ||
Entity Common Stock, Shares Outstanding | 38,626,615 | |
Common Class B | ||
Entity Information [Line Items] | ||
Entity Common Stock, Shares Outstanding | 7,871,512 |
Consolidated balance sheets
Consolidated balance sheets - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Current assets: | ||
Cash and cash equivalents | $ 12,189 | $ 27,732 |
Accounts receivable, net | 70,495 | 60,363 |
Inventories, net | 7,463 | 5,138 |
Prepaid expenses | 2,898 | 2,661 |
Total current assets | 93,045 | 95,894 |
Property and equipment, net | 49,004 | 50,641 |
Oil and natural gas properties, using the full cost method: | ||
Proved | 668,184 | 634,294 |
Unevaluated (excluded from the amortization base) | 550,082 | 482,239 |
Accumulated depreciation, depletion, amortization and impairment | (142,107) | (124,180) |
Total oil and natural gas properties | 1,076,159 | 992,353 |
Other assets | 361 | 418 |
Total assets | 1,218,569 | 1,139,306 |
Current liabilities: | ||
Accounts payable and accrued liabilities | 72,317 | 75,414 |
Accrued payroll and benefits payable | 7,131 | 11,276 |
Accrued interest payable | 576 | 187 |
Revenue distribution payable | 20,118 | 17,966 |
Long-term debt and capital leases, classified as current | 3,306 | 3,273 |
Derivative instruments | 10,548 | 8,959 |
Total current liabilities | 113,996 | 117,075 |
Long-term debt and capital leases, less current maturities | 219,842 | 141,386 |
Derivative instruments | 14,835 | 4,167 |
Deferred compensation | 813 | 696 |
Asset retirement obligations | 33,601 | 33,216 |
Commitments and contingencies (Note 10) | ||
Stockholders’ equity: | ||
Preferred stock | 0 | 0 |
Additional paid in capital | 966,781 | 961,200 |
Treasury stock | (1,422) | |
Accumulated deficit | (130,344) | (118,902) |
Total stockholders' equity | 835,482 | 842,766 |
Total liabilities and stockholders' equity | 1,218,569 | 1,139,306 |
Common Class A | ||
Stockholders’ equity: | ||
Common stock | 388 | 389 |
Common Class B | ||
Stockholders’ equity: | ||
Common stock | $ 79 | $ 79 |
Consolidated balance sheets (Pa
Consolidated balance sheets (Parenthetical) - $ / shares | Mar. 31, 2018 | Dec. 31, 2017 |
Preferred stock, shares authorized | 5,000,000 | 5,000,000 |
Preferred stock, shares issued | 0 | 0 |
Preferred stock, shares outstanding | 0 | 0 |
Treasury stock, shares | 63,919 | |
Common Class A | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 180,000,000 | 180,000,000 |
Common stock, shares issued | 38,872,480 | 38,956,250 |
Common stock, shares outstanding | 38,808,561 | 38,956,250 |
Common Class B | ||
Common stock, par value (in dollars per share) | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 20,000,000 | 20,000,000 |
Common stock, shares issued | 7,871,512 | 7,871,512 |
Common stock, shares outstanding | 7,871,512 | 7,871,512 |
Consolidated statements of oper
Consolidated statements of operations - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 | Mar. 21, 2017 |
Revenues: | |||
Net commodity sales | $ 7,808 | $ 57,889 | |
Sublease revenue | 0 | 1,198 | |
Total revenues | 7,808 | 59,087 | |
Costs and expenses: | |||
Lease operating | 4,259 | 14,543 | |
Transportation and processing | 361 | 3,488 | |
Production taxes | 316 | 2,677 | |
Depreciation, depletion and amortization | 3,414 | 21,106 | |
General and administrative | 5,744 | 11,507 | |
Cost reduction initiatives | 6 | 0 | |
Other | 828 | ||
Total costs and expenses | 14,100 | 50,661 | |
Operating income (loss) | (6,292) | 8,426 | |
Non-operating (expense) income: | |||
Interest expense | (650) | (1,371) | |
Derivative (losses) gains | (12,115) | (16,501) | |
(Loss) gain on sale of assets | 0 | (1,044) | |
Other income (expense), net | (5) | 85 | |
Net non-operating (expense) income | (12,770) | (18,831) | |
Reorganization items, net | (620) | (1,037) | |
(Loss) income before income taxes | (19,682) | (11,442) | |
Income tax expense | 1 | 0 | |
Net (loss) income | $ (19,683) | $ (11,442) | |
Earnings per share: | |||
Basic for Class A and Class B | $ (0.25) | ||
Diluted for Class A and Class B | $ (0.25) | ||
Weighted average shares used to compute earnings per share: | |||
Basic for Class A and Class B | 0 | 45,143,297 | |
Diluted for Class A and Class B | 0 | 45,143,297 | |
Predecessor | |||
Revenues: | |||
Net commodity sales | $ 66,531 | ||
Sublease revenue | 0 | ||
Total revenues | 66,531 | ||
Costs and expenses: | |||
Lease operating | 19,941 | ||
Transportation and processing | 2,034 | ||
Production taxes | 2,417 | ||
Depreciation, depletion and amortization | 24,915 | ||
General and administrative | 6,843 | ||
Cost reduction initiatives | 629 | ||
Total costs and expenses | 56,779 | ||
Operating income (loss) | 9,752 | ||
Non-operating (expense) income: | |||
Interest expense | (5,862) | ||
Derivative (losses) gains | 48,006 | ||
(Loss) gain on sale of assets | 206 | ||
Other income (expense), net | 1,167 | ||
Net non-operating (expense) income | 43,517 | ||
Reorganization items, net | 988,727 | ||
(Loss) income before income taxes | 1,041,996 | ||
Income tax expense | 37 | ||
Net (loss) income | $ 1,041,959 | ||
Weighted average shares used to compute earnings per share: | |||
Basic for Class A and Class B | 0 | ||
Diluted for Class A and Class B | 0 |
Consolidated statements of stoc
Consolidated statements of stockholders' equity - 3 months ended Mar. 31, 2018 - USD ($) $ in Thousands | Total | Common Stock | Additional Paid in Capital | Treasury Stock | Accumulated Deficit |
Stockholders' equity, balance at beginning of the period at Dec. 31, 2017 | $ 842,766 | $ 468 | $ 961,200 | $ (118,902) | |
Balance at beginning of period (in shares) at Dec. 31, 2017 | 46,827,762 | ||||
Stock-based compensation | 5,581 | 5,581 | |||
Restricted stock forfeited | (1) | $ (1) | |||
Restricted stock forfeited (in shares) | (83,770) | ||||
Repurchase of common stock | (1,422) | $ (1,422) | |||
Repurchase of common stock (in shares) | (63,919) | ||||
Net loss | (11,442) | (11,442) | |||
Stockholders' equity, balance at end of the period at Mar. 31, 2018 | $ 835,482 | $ 467 | $ 966,781 | $ (1,422) | $ (130,344) |
Balance at end of period (in shares) at Mar. 31, 2018 | 46,680,073 |
Consolidated statements of cash
Consolidated statements of cash flows - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 | Mar. 21, 2017 |
Cash flows from operating activities | |||
Net (loss) income | $ (19,683) | $ (11,442) | |
Adjustments to reconcile net (loss) income to net cash provided by operating activities | |||
Non-cash reorganization items | 0 | 0 | |
Depreciation, depletion and amortization | 3,414 | 21,106 | |
Derivative losses (gains) | 12,115 | 16,501 | |
Loss (gain) on sale of assets | 0 | 1,044 | |
Other | 1,012 | 1,630 | |
Change in assets and liabilities | |||
Accounts receivable | (3,577) | (12,140) | |
Inventories | 38 | (3,168) | |
Prepaid expenses and other assets | 180 | (179) | |
Accounts payable and accrued liabilities | (3,423) | (9,828) | |
Revenue distribution payable | 1,510 | 2,151 | |
Deferred compensation | 13 | 4,701 | |
Net cash provided by (used in) operating activities | (8,401) | 10,376 | |
Cash flows from investing activities | |||
Expenditures for property, plant, and equipment and oil and natural gas properties | (5,832) | (99,941) | |
Proceeds from asset dispositions | 0 | 73 | |
(Payments) proceeds from derivative instruments | 1,692 | (4,244) | |
Net cash used in investing activities | (4,140) | (104,112) | |
Cash flows from financing activities | |||
Proceeds from long-term debt | 0 | 79,000 | |
Repayment of long-term debt | (19) | (146) | |
Proceeds from rights offering, net | 0 | 0 | |
Principal payments under capital lease obligations | (69) | (661) | |
Payment of other financing fees | 0 | 0 | |
Net cash provided by (used in) financing activities | (88) | 78,193 | |
Net decrease in cash, cash equivalents, and restricted cash | (12,629) | (15,543) | |
Cash, cash equivalents, and restricted cash at beginning of period | 45,123 | 27,732 | |
Cash, cash equivalents, and restricted cash at end of period | 32,494 | $ 12,189 | $ 45,123 |
Predecessor | |||
Cash flows from operating activities | |||
Net (loss) income | 1,041,959 | ||
Adjustments to reconcile net (loss) income to net cash provided by operating activities | |||
Non-cash reorganization items | (1,012,090) | ||
Depreciation, depletion and amortization | 24,915 | ||
Derivative losses (gains) | (48,006) | ||
Loss (gain) on sale of assets | (206) | ||
Other | 645 | ||
Change in assets and liabilities | |||
Accounts receivable | 198 | ||
Inventories | 466 | ||
Prepaid expenses and other assets | (497) | ||
Accounts payable and accrued liabilities | 8,733 | ||
Revenue distribution payable | (1,875) | ||
Deferred compensation | 143 | ||
Net cash provided by (used in) operating activities | 14,385 | ||
Cash flows from investing activities | |||
Expenditures for property, plant, and equipment and oil and natural gas properties | (31,179) | ||
Proceeds from asset dispositions | 1,884 | ||
(Payments) proceeds from derivative instruments | 1,285 | ||
Net cash used in investing activities | (28,010) | ||
Cash flows from financing activities | |||
Proceeds from long-term debt | 270,000 | ||
Repayment of long-term debt | (444,785) | ||
Proceeds from rights offering, net | 50,031 | ||
Principal payments under capital lease obligations | (568) | ||
Payment of other financing fees | (2,410) | ||
Net cash provided by (used in) financing activities | (127,732) | ||
Net decrease in cash, cash equivalents, and restricted cash | (141,357) | ||
Cash, cash equivalents, and restricted cash at beginning of period | $ 45,123 | 186,480 | |
Cash, cash equivalents, and restricted cash at end of period | $ 45,123 |
Nature of operations and summar
Nature of operations and summary of significant accounting policies | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Nature of operations and summary of significant accounting policies | 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 our commodity products include crude oil, natural gas and natural gas liquids. Reorganization, fresh start accounting and comparability of financial statements to prior periods On May 9, 2016, the Company and ten of its subsidiaries filed voluntary petitions seeking relief under Title 11 of the United States 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. On March 10, 2017, 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. Upon emergence, all existing equity was cancelled and we issued new common stock to the previous holders of our Senior Notes and certain general unsecured creditors whose claims were impaired as a result of our bankruptcy, as well as to certain other parties as set forth in the Reorganization Plan, including to parties participating in a rights offering. Additionally, upon emergence we qualified for and applied fresh start accounting to our financial statements in accordance with the provisions set forth in FASB Accounting Standards Codification (ASC) 852: Reorganizations, 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. 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 after March 21, 2017, are not comparable with the consolidated financial statements prior to that date. To facilitate our financial statement presentations, we refer to the post-emergence reorganized company in these consolidated financial statements and footnotes as the “Successor” for periods subsequent to March 21, 2017, and to the pre-emergence company as “Predecessor” for periods prior to and including March 21, 2017. 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, 2017. The financial information as of March 31, 2018 (Successor), and for the three months ended March 31, 2018 (Successor), and the periods of March 22, 2017, through March 31, 2017 (Successor), and January 1, 2017, through March 21, 2017 (Predecessor), is unaudited. The financial information as of December 31, 2017, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2017. 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 March 31, 2018 (Successor) are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2018. Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations. Cash and cash equivalents We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of March 31, 2018, cash with a recorded balance totaling approximately $10,330 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts. Accounts receivable We have receivables from joint interest owners and oil and natural gas purchasers which are generally uncollateralized. Accounts receivable consisted of the following: March 31, December 31, 2018 2017 Joint interests $ 37,339 $ 29,032 Accrued commodity sales 30,761 26,516 Derivative settlements 10 157 Other 3,008 5,326 Allowance for doubtful accounts (623 ) (668 ) $ 70,495 $ 60,363 Inventories Inventories consisted of the following: March 31, December 31, 2018 2017 Equipment inventory $ 6,440 $ 4,163 Commodities 1,202 1,154 Inventory valuation allowance (179 ) (179 ) $ 7,463 $ 5,138 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 the application of fresh start accounting in the first quarter of 2017, 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. The costs of unevaluated oil and natural gas properties consisted of the following: March 31, December 31, 2018 2017 Leasehold acreage $ 527,450 $ 466,711 Capitalized interest 3,655 2,134 Wells and facilities in progress of completion 18,977 13,394 Total unevaluated oil and natural gas properties excluded from amortization $ 550,082 $ 482,239 Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized. Our estimates of oil and natural gas reserves as of March 31, 2018, 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. Producer imbalances. We account for natural gas production imbalances using the sales method, whereby we recognize revenue on all natural gas sold to our customers regardless of our proportionate working interest in a well. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated natural gas reserves. Our aggregate imbalance positions at March 31, 2018, and December 31, 2017, were immaterial. Income taxes In December 2017, the President of the United States signed into law the Tax Cuts and Jobs Act of 2017 (the “Act”), making significant changes to the Internal Revenue Code. Changes include, but are not limited to, a federal corporate tax rate of 21%, additional limitations on executive compensation, and limitations on the deductibility of interest. The FASB issued Accounting Standards Update (“ASU”) 2018-05, Income Taxes (Topic 740): "Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin (“SAB”) No. 118" to address the application of GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Act. As of March 31, 2018, we had not completed our accounting with regard to Section 162(m) provisions under the Act, and anticipate completing our analysis prior to filing our 2017 tax return in the third quarter of 2018, which is within the one year measurement period required under SAB 118. As such, we have not made an adjustment to the provisional tax benefit recorded under SAB 118 at December 31, 2017. We have estimated our provision for income taxes in accordance with the Act and guidance available as of the date of this filing. Despite the Company’s net loss for the quarter ended March 31, 2018 we did not record any net deferred tax benefit for the quarter ended March 31, 2018, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured. 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. 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 March 31, 2018, or December 31, 2017. 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. Loss on asset sale. In November 2017, we closed on the sale of our EOR assets. In conjunction with this divestiture, we recorded a loss on sale of $25,163 during the fourth quarter of 2017, which was computed based on preliminary closing estimates. As a result of the final closing adjustments on the sale, we recorded an additional loss of $1,064 during the first quarter of 2018. Other Other includes certain expenses related to our restructuring and subleasing activities. Restructuring Subleases . Prior to the sale of our EOR assets in November 2017, we utilized CO 2 Joint Venture On September 25, 2017, we entered into a joint development agreement (“JDA”) with BCE Roadrunner LLC, a wholly-owned subsidiary of Bayou City Energy Management, LLC (“BCE”), pursuant to which BCE will fund 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: Successor Predecessor Period from Period from March 22, 2017 January 1, 2017 through through March 31, 2017 March 21, 2017 One-time severance and termination benefits $ 1 $ 608 Professional fees 5 21 Total cost reduction initiatives expense $ 6 $ 629 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. “Professional fees” in the table below for periods subsequent to the Effective Date are comprised of legal fees for continuing work to resolve outstanding bankruptcy claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until our bankruptcy case is closed. Reorganization items are as follows: Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through March 31, 2018 March 31, 2017 March 21, 2017 Loss (gain) on the settlement of liabilities subject to compromise $ 48 $ — $ (372,093 ) Fresh start accounting adjustments — — (641,684 ) Professional fees 989 620 18,790 Rejection of employment contracts — — 4,573 Write off unamortized issuance costs on Prior Credit Facility — — 1,687 Total reorganization items $ 1,037 $ 620 $ (988,727 ) Recently adopted accounting pronouncements In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Please see “Note 5—Revenue recognition” for our disclosure regarding adoption of this update. In January 2017, the FASB issued authoritative guidance that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described under updated revenue recognition guidance. The guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. We adopted this update effective January 1, 2018, without a material impact to our financial statements. We expect that the new guidance, when applied to the facts and circumstances of a future transaction, may impact the likelihood whether a future transaction would be accounted for as a business combination. In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods thereafter. We adopted this update effective January 1, 2018, with no material impact to our financial statements or results of operations. In August 2016, the FASB issued authoritative guidance which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable. We adopted this update effective January 1, 2018, without a material impact on our financial statements or results of operations. In November 2016, the FASB issued authoritative guidance requiring that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and should be applied using a retrospective transition method to each period presented. We adopted this update effective January 1, 2018, with no material impact to our financial statements or results of operations. Recently issued accounting pronouncements 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. Our current operating leases are predominantly comprised of a limited number of leases for CO 2 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. |
Earnings Per Share
Earnings Per Share | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Earnings Per Share | 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. A reconciliation of the components of basic and diluted EPS is presented below: Three months ended (in thousands, except share and per share data) March 31, 2018 Numerator for basic and diluted earnings per share Net loss $ (11,442 ) Denominator for basic earnings per share Weighted average common shares - Basic for Class A and Class B 45,143,297 Denominator for diluted earnings per share Weighted average common shares - Diluted for Class A and Class B 45,143,297 Earnings per share Basic for Class A and Class B $ (0.25 ) Diluted for Class A and Class B $ (0.25 ) Participating securities excluded from earnings per share calculations Unvested restricted stock awards (2) 1,589,332 Antidilutive securities excluded from earnings per share calculations Warrants (1) 140,023 ________________________________ (1) The warrants to purchase shares of our Class A common stock are antidilutive due to the exercise price exceeding the average price of our Class A shares for the periods presented and due to the net losses we incurred. (2) 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. |
Supplemental disclosures to the
Supplemental disclosures to the consolidated statements of cash flows | 3 Months Ended |
Mar. 31, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental disclosures to the consolidated statements of cash flows | Note 3: Supplemental disclosures to the consolidated statements of cash flows Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through March 31, 2018 March 31, 2017 March 21, 2017 Net cash provided by operating activities included: Cash payments for interest $ 2,206 $ 2,768 $ 4,105 Interest capitalized (1,521 ) (54 ) (248 ) Cash payments for interest, net of amounts capitalized $ 685 $ 2,714 $ 3,857 Cash payments for reorganization items $ 410 $ — $ 11,405 Non-cash investing activities included: Asset retirement obligation additions and revisions $ 213 $ — $ 716 Change in accrued oil and gas capital expenditures $ 705 $ — $ 5,387 |
Debt and Capital Leases
Debt and Capital Leases | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Debt and Capital Leases | Note 4: Debt and capital leases As of the dates indicated, long-term debt and capital leases consisted of the following: March 31, December 31, 2018 2017 New Credit Facility $ 206,100 $ 127,100 Real estate mortgage note 9,031 9,177 Capital lease obligations 13,699 14,361 Unamortized debt issuance costs (5,682 ) (5,979 ) Total debt, net 223,148 144,659 Less current portion 3,306 3,273 Total long-term debt, net $ 219,842 $ 141,386 New Credit Facility The New Credit Facility is a $400,000 facility collateralized by our oil and natural gas properties and is scheduled to mature on December 21, 2022. Availability under our New Credit Facility 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. Availability on the New Credit Facility as of March 31, 2018, after taking into account outstanding borrowings and letters of credit on that date, was $78,072. As of March 31, 2018, our outstanding borrowings were accruing interest at the Adjusted LIBO Rate (as defined in the New Credit Facility), plus the Applicable Margin (as defined in the New Credit Facility), which resulted in a weighted average interest rate of 4.86%. The New Credit Facility contains financial covenants that require, for each fiscal quarter, we maintain: (1) a Current Ratio (as defined in the New Credit Facility) of no less than 1.00 to 1.00, and (2) a Ratio of Total Debt to EBITDAX (as defined in the New Credit Facility) of no greater than 4.0 to 1.0 calculated on a trailing four-quarter basis. We were in compliance with these financials covenants as of March 31, 2018. The New Credit Facility contains covenants and events of default customary for oil and natural gas reserve-based lending facilities. Please see “Note 8—Debt” in Item 8 Financial Statements and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2017, for a discussion of the material provisions of our New Credit Facility. Effective May 9, 2018, we entered into the First Amendment to the Tenth Restated Credit Agreement, among the Company and its subsidiaries, as borrowers, certain financial institutions party thereto, as lenders, and JPMorgan Chase Bank, N.A., as administrative agent (the “Amendment”). The Amendment reaffirmed our borrowing base at the same level of $285,000. In addition, the Amendment provided us with: (i) an increase from $150,000 to $250,000 to the aggregate amount of secured debt allowed, (ii) a waiver on the automatic reduction to the borrowing base calculation for the issuance of up to $300,000 in unsecured debt, (iii) the ability to offset the total debt calculation in the financial covenant calculations by up to $50,000 of unrestricted cash and cash equivalents whenever we do not have outstanding borrowings on the facility, and (iv) permission to make payments on account of the purchase, redemption, retirement, acquisition, cancellation or termination of our equity of up to $50,000. Capital Leases In 2013, we entered into lease financing agreements with U.S. Bank 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. In conjunction with the sale of our EOR assets, these compressors were subleased to the buyer of those assets although we remain the primary obligor in relation to U.S. Bank. |
Revenue Recognition
Revenue Recognition | 3 Months Ended |
Mar. 31, 2018 | |
Revenue From Contract With Customer [Abstract] | |
Revenue Recognition | Note 5: Revenue Recognition In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements which has been codified as Accounting Standards Codification 606: Revenue from Contracts with Customers (“ASC 606”). ASC 606 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. Description of products and revenue disaggregation Our revenue is predominantly derived from the production and sale of oil, natural gas and NGLs which, prior to January 1, 2018, was reported in the aggregate as “Commodity sales” on our statement of operations. Substantially all our oil and natural gas properties are located in Oklahoma and Texas and are sold to midstream gas processing plants or crude oil refineries in the vicinity. We have disaggregated revenue based on the separate commodities being sold: crude oil, natural gas and NGLs. In selecting the disaggregation categories, we considered a number of factors such as those affecting supply and demand and thus market prices, storage and the ability to transport the product, industry specific disclosures required by the SEC and FASB, other external disclosures we typically make, and information we have historically presented in the management discussion and analysis section of our annual and quarterly reports. As such, we believe that disaggregating revenue by commodity type appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The following table displays the revenue disaggregated and reconciles the disaggregated revenue to the revenue reported: (in thousands) Three months ended March 31, 2018 Revenues: Oil $ 43,050 Natural gas 8,736 Natural gas liquids 9,591 Gross commodity sales 61,377 Transportation and processing (3,488 ) Net commodity sales 57,889 Performance Obligations Our oil, natural gas and natural gas liquids contracts typically contain only one type of performance obligation, which is for the delivery of the underlying commodity, and which is satisfied at the point in time the commodity is transferred to the customer. We consider each commodity (ex. barrel of oil or MMBtu of natural gas) to be a separate performance obligation. For natural gas and natural gas liquids, all our sales are to midstream processing entities engaged in the processing of gas and marketing the resulting residue gas and NGLs to third party customers. We transfer control of the product to the midstream processing customer at the wellhead and recognize revenue upon such delivery. Under our oil sales contracts, we generally sell oil to the purchaser from storage tanks near the wellhead and collect a contractually agreed upon index price, net of pricing differentials. We transfer control of the product from the storage tanks to the purchaser and recognize revenue based on the contract price. We do not engage in activities to purchase and sell third party natural gas and NGLs. As a result, the commodity revenues we recognize are only for our working interest share of the production. Pricing and measurement All of our contracts use market or index-based pricing resulting in the entire transaction price being variable. Since our sales transactions meet the variable allocation criteria in the standard, all consideration is allocated entirely to performance obligations satisfied by distinct commodity units delivered. We record revenue in the month production is delivered to the purchaser. However, settlement statements for our commodity sales are received one to three months after the date production is delivered, and as a result, we are required to estimate the amount of production that was delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts for product sales in the month that payment is received from the purchaser. Historically, differences between our revenue estimates and actual revenue received have not been significant. We receive payment for a majority of our sales receivables in the month following delivery and substantially all within three months following delivery. For the three months ended March 31, 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material. Transaction Price Allocated to Remaining Performance Obligations For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Since each unit of product delivered to the customer represents a separate performance obligation; therefore, future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required. For our product sales that have a contract term of one year or less, we have utilized the practical expedient in ASC 606, which states that a company is not required to disclose the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less. Nature of gas contracts All our natural gas and NGL production is sold to midstream processing entities and we do not elect to take our residue gas and/or NGLs in-kind at the tailgate of processing plant. The midstream customer provides us with services such as compressing the gas, transporting the gas to the processing plant and processing it into the separate commodity streams for fees which are deducted from the revenue we receive. We previously reported fees for these services as “Transportation and processing” expenses in our statement of operations. Under ASC 606, since control and possession of the gas is transferred to the customer at the wellhead prior to the receipt of the aforementioned services, the customer is not deemed to be providing a distinct service and any fees paid to the customer are accounted for as a reduction in revenue. We have presented transportation and processing fees as a revenue deduction for the fiscal period beginning January 1, 2018, while our presentation for prior periods remains unchanged Contract assets and liabilities We recognize a receivable for the unconditional right to receive consideration when the commodity is transferred to the customer, at which point the performance obligation is satisfied. All our contract assets are in the form of receivables which are presented as “Accrued commodity sales” in our tabular disclosure of accounts receivable in Note 1—Nature of operations and summary of significant accounting policies. Since we are not entitled to advance payments from our customers prior to the transfer of our commodities nor do receive such payments, we do not have contract liabilities . Method of adoption W e adopted ASC 606 effective January 1, 2018 using the modified retrospective approach. Based on an assessment of our contracts, the new guidance did not have a material impact on prior net income and therefore we did not record a cumulative effect adjustment to the opening balance of accumulated deficit Reconciliation of Income Statement In accordance with ASC 606, the disclosure of the impact of adoption on our income statement is as follows: Three months ended March 31, 2018 (in thousands) As reported Balances without adoption of ASC 606 Effect of change Revenues Net commodity sales $ 57,889 $ 61,377 $ (3,488 ) Costs and expenses Transportation and processing $ — $ (3,488 ) $ 3,488 |
Derivative instruments
Derivative instruments | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Derivative instruments | Note 6: Derivative instruments Overview Our results of operations, financial condition and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil, natural gas and natural gas liquids. These commodity prices are subject to wide fluctuations and market uncertainties. To mitigate a portion of this exposure, we enter into various types of derivative instruments, including commodity price swaps, collars, put options, enhanced swaps and basis protection swaps. See “Note 9—Derivative Instruments” in Item 8. Financial Statement and Supplementary Data of our Annual Report on Form 10-K for the year ended December 31, 2017, for a description of the various kinds of derivatives we may enter into. The following table summarizes our crude oil derivatives outstanding as of March 31, 2018: Weighted average fixed price per Bbl Period and type of contract Volume MBbls Swaps Purchased puts Sold calls 2018 Swaps 1,576 $ 58.14 $ — $ — Collars 138 $ — $ 50.00 $ 60.50 2019 Swaps 1,312 $ 54.26 $ — $ — 2020 Swaps 1,548 $ 49.54 $ — $ — 2021 Swaps 543 $ 44.34 $ — $ — The following table summarizes our natural gas derivatives outstanding as of March 31, 2018: Period and type of contract Volume BBtu Weighted average fixed price per MMBtu 2018 Swaps 7,911 $ 2.87 2019 Swaps 7,632 $ 2.81 2020 Swaps 3,600 $ 2.77 In February 2018, we renegotiated the fixed pricing of certain crude oil swaps scheduled to settle during 2018 in exchange for entering crude oil swaps, scheduled to settle from 2020 through 2021, at lower-than-market pricing. The renegotiated swaps cover 1,086 MBbls and have a new fixed price of $60.00 per barrel, replacing the original weighted average fixed price of $54.80 per barrel. The new crude oil swaps scheduled to settle from 2020 through 2021 have weighted average fixed prices of $46.26 and $44.34 per barrel, respectively, and cover 543 MBbls each year. Effect of derivative instruments on the consolidated balance sheets All derivative financial instruments are recorded on the balance sheet at fair value. See “Note 7—Fair value measurements” for additional information regarding fair value measurements. The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values. As of March 31, 2018 As of December 31, 2017 Assets Liabilities Net value Assets Liabilities Net value Natural gas derivative contracts $ 1,120 $ (671 ) $ 449 $ 1,332 $ (1,054 ) $ 278 Crude oil derivative contracts — (25,832 ) (25,832 ) — (13,404 ) (13,404 ) Total derivative instruments 1,120 (26,503 ) (25,383 ) 1,332 (14,458 ) (13,126 ) Less: Netting adjustments (1) 1,120 (1,120 ) — 1,332 (1,332 ) — Derivative instruments - current — (10,548 ) (10,548 ) — (8,959 ) (8,959 ) Derivative instruments - long-term $ — $ (14,835 ) $ (14,835 ) $ — $ (4,167 ) $ (4,167 ) (1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet. 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: Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through March 31, 2018 March 31, 2017 March 21, 2017 Change in fair value of commodity price derivatives $ (12,257 ) $ (13,807 ) $ 46,721 Settlements (paid) received on commodity price derivatives (4,244 ) 1,692 1,285 Total derivative (losses) gains $ (16,501 ) $ (12,115 ) $ 48,006 |
Fair value measurements
Fair value measurements | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair value measurements | Note 7: Fair value measurements Fair value is defined by the FASB as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity. Fair value measurements are categorized according to the fair value hierarchy defined by the FASB. The hierarchical levels are based upon the level of judgment associated with the inputs used to measure the fair value of the assets and liabilities as follows: • Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. • Level 2 inputs include quoted prices for identical or similar instruments in markets that are not active and inputs other than quoted prices that are observable for the asset or liability. • Level 3 inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. 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 March 31, 2018, and December 31, 2017, our financial instruments recorded at fair value on a recurring basis consisted of commodity derivative contracts (see “Note 6—Derivative instruments”). We had no Level 1 assets or liabilities. Our derivative contracts classified as Level 2 consisted of commodity price swaps which are valued using an income approach. Future cash flows from the commodity price swaps are estimated based on the difference between the fixed contract price and the underlying published forward market price. Our derivative contracts classified as Level 3 consisted of collars. The fair value of these contracts is developed by a third-party pricing service using a proprietary valuation model, which we believe incorporates the assumptions that market participants would have made at the end of each period. Observable inputs include contractual terms, published forward pricing curves, and yield curves. Significant unobservable inputs are implied volatilities. Significant increases (decreases) in implied volatilities in isolation would result in a significantly higher (lower) fair value measurement. We review these valuations and the changes in the fair value measurements for reasonableness. All derivative instruments are recorded at fair value and include a measure of our own nonperformance risk for derivative liabilities or our counterparty credit risk for derivative assets. The fair value hierarchy for our financial assets and liabilities is shown by the following table: As of March 31, 2018 As of December 31, 2017 Derivative assets Derivative liabilities Net assets (liabilities) Derivative assets Derivative liabilities Net assets (liabilities) Significant other observable inputs (Level 2) $ 1,120 $ (25,884 ) $ (24,764 ) $ 1,332 $ (14,163 ) $ (12,831 ) Significant unobservable inputs (Level 3) — (619 ) (619 ) — (295 ) (295 ) Netting adjustments (1) (1,120 ) 1,120 — (1,332 ) 1,332 — $ — $ (25,383 ) $ (25,383 ) $ — $ (13,126 ) $ (13,126 ) (1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification. 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: Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through Net derivative assets (liabilities) March 31, 2018 March 31, 2017 March 21, 2017 Beginning balance $ (295 ) $ 715 $ (98 ) Realized and unrealized (losses) gains included in derivative (losses) gains (432 ) (239 ) 813 Settlements paid 108 — — Ending balance $ (619 ) $ 476 $ 715 (Losses) gains relating to instruments still held at the reporting date included in derivative (losses) gains for the period $ (380 ) $ (239 ) $ 813 Nonrecurring fair value measurements Asset retirement obligations. Additions to the asset and liability associated with our asset retirement obligations are measured at fair value on a nonrecurring basis. Our asset retirement obligations consist of the estimated present value of future costs to plug and abandon or otherwise dispose of our oil and natural gas properties and related facilities. Significant inputs used in determining such obligations include estimates of plugging and abandonment costs, inflation rates, discount rates, and well life, all of which are Level 3 inputs according to the fair value hierarchy. The estimated future costs to dispose of properties added during the first three months of 2018 and 2017 were escalated using an annual inflation rate of 2.26% and 2.30%, respectively. The estimated future costs to dispose of properties added during the three months ended March 31, 2018, 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 6.92% to 7.15%. For the properties added during the period from March 22, 2017, through March 31, 2017, a credit-adjusted risk-free rate range from 5.20% to 7.40% was used. These estimates may change based upon future inflation rates and changes in statutory remediation rules. See “Note 8—Asset retirement obligations” for additional information regarding our asset retirement obligations. Fair value of other financial instruments Our significant financial instruments, other than derivatives, consist primarily of cash and cash equivalents, accounts receivable, accounts payable, and debt. We believe the carrying values of cash and cash equivalents, accounts receivable, and accounts payable approximate fair values due to the short-term maturities of these instruments. The carrying value and estimated fair value of our debt were as follows: March 31, 2018 December 31, 2017 Level 2 Carrying value (1) Estimated fair value Carrying value (1) Estimated fair value New Credit Facility $ 206,100 $ 206,100 $ 127,100 $ 127,100 Other secured debt 9,031 9,031 9,177 9,177 (1) The carrying value excludes deductions for debt issuance costs. The carrying value of our New Credit Facility 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. Counterparty credit risk Our derivative contracts are executed with institutions, or affiliates of institutions, that are parties to our credit facilities at the time of execution, and we believe the credit risks associated with all of these institutions are acceptable. We do not require collateral or other security from counterparties to support derivative instruments. Master agreements are in place with each of our derivative counterparties which provide for net settlement in the event of default or termination of the contracts under each respective agreement. As a result of the netting provisions, our maximum amount of loss under derivative transactions due to credit risk is limited to the net amounts due from the counterparties under the derivatives. Our loss is further limited as any amounts due from a defaulting counterparty that is a Lender, or an affiliate of a Lender, under our credit facilities can be offset against amounts owed to such counterparty Lender. As of March 31, 2018, the counterparties to our open derivative contracts consisted of four financial institutions, of which all were lenders under our New Credit Facility. The following table summarizes our derivative assets and liabilities which are offset in the consolidated balance sheets under our master netting agreements. It also reflects the amounts outstanding under our credit facilities that are available to offset our net derivative assets due from counterparties that are lenders under our credit facilities. Offset in the consolidated balance sheets Gross amounts not offset in the consolidated balance sheets Gross assets (liabilities) Offsetting assets (liabilities) Net assets (liabilities) Derivatives (1) Amounts outstanding under credit facilities (2) Net amount March 31, 2018 Derivative assets $ 1,120 $ (1,120 ) $ — $ — $ — $ — Derivative liabilities (26,503 ) 1,120 (25,383 ) — — (25,383 ) $ (25,383 ) $ — $ (25,383 ) $ — $ — $ (25,383 ) December 31, 2017 Derivative assets $ 1,332 $ (1,332 ) $ — $ — $ — $ — Derivative liabilities (14,458 ) 1,332 (13,126 ) — — (13,126 ) $ (13,126 ) $ — $ (13,126 ) $ — $ — $ (13,126 ) _____________________________________________________ (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. (2) The amount outstanding under our New Credit Facility that is available to offset our net derivative assets due from counterparties that are lenders under our New Credit Facility. We did not post additional collateral under any of these contracts as all of our counterparties are secured by the collateral under our 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 $26,503 before offsets at March 31, 2018. |
Asset retirement obligations
Asset retirement obligations | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset retirement obligations | Note 8: Asset retirement obligations The following table provides a summary of our asset retirement obligation activity: Three months ended March 31, 2018 Beginning balance $ 35,990 Liabilities incurred in current period 48 Liabilities settled or disposed in current period (385 ) Revisions in estimated cash flows 165 Accretion expense 532 Ending balance $ 36,350 Less current portion included in accounts payable and accrued liabilities 2,749 Asset retirement obligations, long-term $ 33,601 See “Note 7—Fair value measurements” for additional information regarding fair value assumptions associated with our asset retirement obligations. |
Deferred compensation
Deferred compensation | 3 Months Ended |
Mar. 31, 2018 | |
Share Based Compensation [Abstract] | |
Deferred Compensation | Note 9: Deferred compensation Cash Incentive Plan We adopted the Long-Term Cash Incentive Plan (the “Cash LTIP”) on August 7, 2015. The Cash LTIP provides additional cash compensation to certain employees of the Company in the form of awards that generally vest in equal annual increments over a four-year period. Since the awards do not vary according to the value of the Company’s equity, the awards are not considered “stock-based compensation” under accounting guidance. We accrue for the cost of each annual increment over the period service is required to vest. A summary of compensation expense for the Cash LTIP is presented below: Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through March 31, 2018 March 31, 2017 March 21, 2017 Cash LTIP expense (net of amounts capitalized) $ 95 $ 13 $ 5 Cash LTIP payments 17 — 42 As of March 31, 2018, the outstanding liability accrued for our Cash LTIP, based on requisite service provided, was $1,678. 2010 Equity Incentive Plan Prior to the Effective Date, stock awards were granted under the Chaparral Energy, Inc. 2010 Equity Incentive Plan (the “2010 Plan”) which was implemented on April 12, 2010. The awards granted under the 2010 Plan consisted of shares that were subject to service vesting conditions and shares that were subject to market and performance vested conditions. As of result of our bankruptcy and subsequent emergence, all unvested restricted stock was cancelled on the Effective Date. 2017 Management Incentive Plan 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: 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, we have granted restricted stock 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. Both the Time and Performance Shares are classified as equity-based awards. Compensation cost is generally 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. The Performance Shares vest in three tranches annually according to performance conditions established each year which generally relate to profitability, drilling results and other strategic goals. As of March 31, 2018, performance conditions had not been established for 2018 and 2019 and hence a grant date with respect to Performance Shares allocated to those tranches had not been established for accounting purposes and no expense was accrued for these awards during the three months ended March 31, 2018. Performance conditions for 2018 were subsequently established and approved by our Board in May 2018 and we have commenced recognizing expense for the related shares in the second quarter of 2018. A summary of our restricted stock activity pursuant to our MIP is presented below: Time Shares Performance Shares Weighted average grant date fair value Restricted shares Weighted average grant date fair value Restricted shares ($ per share) ($ per share) Unvested and outstanding at January 1, 2018 (1) $ 20.11 1,403,626 $ 20.15 269,476 Granted $ — — $ — — Vested $ — — $ — — Forfeited $ 20.05 (68,540 ) $ 20.05 (15,230 ) Unvested and outstanding at March 31, 2018 $ 20.12 1,335,086 $ 20.17 254,246 _______________________________________________________ (1) The beginning balance of Performance Shares relate to tranches with performance goals for 2018 and 2019. As of March 31, 2018, the goals had not been approved and hence a grant date had not been established and requisite service has not begun. 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. 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: Successor Predecessor Three months ended March 31, 2018 Period from March 22, 2017 through March 31, 2017 Period from January 1, 2017 through March 21, 2017 Stock-based compensation cost $ 5,580 $ — $ 194 Less: stock-based compensation cost capitalized (957 ) — (39 ) Stock-based compensation expense (credit) $ 4,623 $ — $ 155 Payments for stock-based compensation $ 1,422 $ — $ — Based on a quarter end market price of $17.75 per share of our common stock, the aggregate intrinsic value of all restricted shares outstanding was $28,211 as of March 31, 2018. The payments disclosed in the table above for the three months ended March 31, 2018, were for repurchases of 63,919 shares for tax withholding related to a vesting that occurred on December 31, 2017. In April 2018, we repurchased an additional 181,946 shares for tax withholding for $3,220 on a vesting that occurred during the month. We do not expect to make any material repurchases of vested shares for the next 12 months. As of March 31, 2018, and December 31, 2017, 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 $12,567 as of March 31, 2018, is expected to be recognized over a weighted-average period of 1.6 years. |
Commitments and contingencies
Commitments and contingencies | 3 Months Ended |
Mar. 31, 2018 | |
Commitments And Contingencies Disclosure [Abstract] | |
Commitments and contingencies | Note 10: 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 March 31, 2018, and December 31, 2017. 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 three months ended March 31, 2018 or 2017. 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. 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 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% . The appeal has been fully briefed, and oral arguments were held on March 20, 2018. In addition to filing claims on behalf of the named and putative plaintiffs, 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. 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 has not responded to the plaintiffs’ motions. After plaintiff’s motion for reconsideration was denied, plaintiffs filed a Notice of Appeal with the Tenth Circuit Court of Appeals on December 6, 2016. Oral argument regarding the appeal was held on November 14, 2017, and on April 5, 2018, the Tenth Circuit affirmed the dismissal. The time to appeal the Tenth Circuit’s ruling has not lapsed. We anticipate any monetary liability related to this claim will be discharged. We dispute plaintiffs’ allegations and dispute that the case meets the requirements for a class action . Lisa West and Stormy Hopson, individually and as class representatives on behalf of all similarly situated persons v. Chaparral Energy, L.L.C. On February 18, 2016, an alleged class action was filed against us, as well as several other operators in the District Court of Pottawatomie County, State of Oklahoma, 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. 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. W e 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 and on February 9, 2018, the Bankruptcy Court granted our objection to class treatment of the proof of claim. 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 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. The case was removed to the Western District of Oklahoma on December 15, 2017, and on December 18, 2017, plaintiffs voluntarily dismissed us from the suit without prejudice. Due to subsequent remand to state court, we filed notice of the dismissal in the state court action on January 31, 2018. 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. On December 18, 2018, we moved the court to dismiss the claims against us. Prior to plaintiffs responding to our motion, a hearing on a motion to stay the Butler case was held on January 4, 2018. The judge granted the motion to stay proceedings, ruling from the bench that the Butler case was stayed pending final judgment or denial of class certification in the case. Our motion to dismiss will not be considered until the stay is lifted, at which time, if necessary, we will dispute plaintiffs’ claims, dispute that the remedies requested are available under Oklahoma law, and vigorously defend the case . Lacheverjuan Bennett et al. v. Chaparral Energy, L.L.C., et al . On March 26, 2018, a group of twenty-seven individual plaintiffs filed a lawsuit in the District Court of Logan County, State of Oklahoma against twenty-three named defendants, including us, and twenty-five unnamed defendants. Plaintiffs are all property owners and residents of Logan County, Oklahoma, and allege the defendants, all oil and gas companies which have engaged in injection well operations, induced earthquakes which have caused damage to real and personal property, and caused emotional damages. Plaintiffs claim absolute liability for ultra-hazardous activities, negligence, gross negligence, public and private nuisance, and trespass, and ask for compensatory and punitive damages, and attorney fees and costs. Jointly with other defendants, we filed a motion to stay the proceedings pending resolution of related earthquake litigation. We dispute the plaintiffs’ claims, dispute the remedies requested are available under Oklahoma law, and are vigorously defending the case . We are involved in various other legal proceedings including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, employment claims, and other matters which arise in the ordinary course of business. In addition, other proofs of claim have been filed in our bankruptcy case which we anticipate repudiating. While the outcome of these legal proceedings cannot be predicted with certainty, we do not expect any of them individually to have a material effect on our financial condition, results of operations or cash flows . We have numerous contractual commitments in the ordinary course of business including debt service requirements, operating leases, capital leases and purchase obligations. Our operating leases primarily relate to CO 2 2 2 |
Nature of operations and summ17
Nature of operations and summary of significant accounting policies (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Nature of operations | 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 our commodity products include crude oil, natural gas and natural gas liquids. |
Interim financial statements | 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, 2017. The financial information as of March 31, 2018 (Successor), and for the three months ended March 31, 2018 (Successor), and the periods of March 22, 2017, through March 31, 2017 (Successor), and January 1, 2017, through March 21, 2017 (Predecessor), is unaudited. The financial information as of December 31, 2017, has been derived from the audited financial statements contained in our Annual Report on Form 10-K for the year ended December 31, 2017. 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 March 31, 2018 (Successor) are not necessarily indicative of the results of operations that will be realized for the year ended December 31, 2018. Certain reclassifications have been made to prior period financial statements to conform to current period presentation. The reclassifications had no effect on our previously reported results of operations. |
Cash and cash equivalents | Cash and cash equivalents We maintain cash and cash equivalents in bank deposit accounts and money market funds which may not be federally insured. As of March 31, 2018, cash with a recorded balance totaling approximately $10,330 was held at JP Morgan Chase Bank, N.A. We have not experienced any losses in such accounts and believe we are not exposed to any significant credit risk on such accounts. |
Accounts receivable | 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: March 31, December 31, 2018 2017 Joint interests $ 37,339 $ 29,032 Accrued commodity sales 30,761 26,516 Derivative settlements 10 157 Other 3,008 5,326 Allowance for doubtful accounts (623 ) (668 ) $ 70,495 $ 60,363 |
Inventories | Inventories Inventories consisted of the following: March 31, December 31, 2018 2017 Equipment inventory $ 6,440 $ 4,163 Commodities 1,202 1,154 Inventory valuation allowance (179 ) (179 ) $ 7,463 $ 5,138 |
Oil and natural gas properties | 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 the application of fresh start accounting in the first quarter of 2017, 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. The costs of unevaluated oil and natural gas properties consisted of the following: March 31, December 31, 2018 2017 Leasehold acreage $ 527,450 $ 466,711 Capitalized interest 3,655 2,134 Wells and facilities in progress of completion 18,977 13,394 Total unevaluated oil and natural gas properties excluded from amortization $ 550,082 $ 482,239 Ceiling Test. In accordance with the full cost method of accounting, the net capitalized costs of oil and natural gas properties are not to exceed their related PV-10 value, net of tax considerations, plus the cost of unproved properties not being amortized. Our estimates of oil and natural gas reserves as of March 31, 2018, 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. Producer imbalances. We account for natural gas production imbalances using the sales method, whereby we recognize revenue on all natural gas sold to our customers regardless of our proportionate working interest in a well. Liabilities are recorded for imbalances greater than our proportionate share of remaining estimated natural gas reserves. Our aggregate imbalance positions at March 31, 2018, and December 31, 2017, were immaterial. |
Income taxes | Income taxes In December 2017, the President of the United States signed into law the Tax Cuts and Jobs Act of 2017 (the “Act”), making significant changes to the Internal Revenue Code. Changes include, but are not limited to, a federal corporate tax rate of 21%, additional limitations on executive compensation, and limitations on the deductibility of interest. The FASB issued Accounting Standards Update (“ASU”) 2018-05, Income Taxes (Topic 740): "Amendments to SEC Paragraphs Pursuant to SEC Staff Accounting Bulletin (“SAB”) No. 118" to address the application of GAAP in situations when a registrant does not have the necessary information available, prepared, or analyzed (including computations) in reasonable detail to complete the accounting for certain income tax effects of the Act. As of March 31, 2018, we had not completed our accounting with regard to Section 162(m) provisions under the Act, and anticipate completing our analysis prior to filing our 2017 tax return in the third quarter of 2018, which is within the one year measurement period required under SAB 118. As such, we have not made an adjustment to the provisional tax benefit recorded under SAB 118 at December 31, 2017. We have estimated our provision for income taxes in accordance with the Act and guidance available as of the date of this filing. Despite the Company’s net loss for the quarter ended March 31, 2018 we did not record any net deferred tax benefit for the quarter ended March 31, 2018, as any deferred tax asset arising from the benefit is reduced by a valuation allowance as utilization of the loss carryforwards and realization of other deferred tax assets cannot be reasonably assured. 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. 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 March 31, 2018, or December 31, 2017. 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. |
Other | Other Subleases . Prior to the sale of our EOR assets in November 2017, we utilized CO 2 |
Cost reduction initiatives | 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: Successor Predecessor Period from Period from March 22, 2017 January 1, 2017 through through March 31, 2017 March 21, 2017 One-time severance and termination benefits $ 1 $ 608 Professional fees 5 21 Total cost reduction initiatives expense $ 6 $ 629 |
Reorganization items | 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. “Professional fees” in the table below for periods subsequent to the Effective Date are comprised of legal fees for continuing work to resolve outstanding bankruptcy claims and fees to the U.S. Bankruptcy Trustee, which we will continue to incur until our bankruptcy case is closed. Reorganization items are as follows: Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through March 31, 2018 March 31, 2017 March 21, 2017 Loss (gain) on the settlement of liabilities subject to compromise $ 48 $ — $ (372,093 ) Fresh start accounting adjustments — — (641,684 ) Professional fees 989 620 18,790 Rejection of employment contracts — — 4,573 Write off unamortized issuance costs on Prior Credit Facility — — 1,687 Total reorganization items $ 1,037 $ 620 $ (988,727 ) |
Recently issued and adopted accounting pronouncements | Recently adopted accounting pronouncements In May 2014, the FASB issued authoritative guidance that supersedes previous revenue recognition requirements and requires entities to recognize revenue in a way that depicts the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. Please see “Note 5—Revenue recognition” for our disclosure regarding adoption of this update. In January 2017, the FASB issued authoritative guidance that changes the definition of a business to assist entities with evaluating when a set of transferred assets and activities constitutes a business. The guidance requires an entity to evaluate if substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or a group of similar identifiable assets; if so, the set of transferred assets and activities is not a business. The guidance also requires a business to include at least one substantive process and narrows the definition of outputs by more closely aligning it with how outputs are described under updated revenue recognition guidance. The guidance is effective for public business entities for fiscal years beginning after December 15, 2017, and interim periods within those years. We adopted this update effective January 1, 2018, without a material impact to our financial statements. We expect that the new guidance, when applied to the facts and circumstances of a future transaction, may impact the likelihood whether a future transaction would be accounted for as a business combination. In January 2016, the FASB issued authoritative guidance that amends existing requirements on the classification and measurement of financial instruments. The standard principally affects accounting for equity investments and financial liabilities where the fair value option has been elected. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods thereafter. We adopted this update effective January 1, 2018, with no material impact to our financial statements or results of operations. In August 2016, the FASB issued authoritative guidance which provides clarification on how certain cash receipts and cash payments are presented and classified on the statement of cash flows. This update provides guidance on eight specific cash flow issues: debt prepayment or debt extinguishment costs; settlement of zero-coupon debt instruments or other debt instruments with coupon interest rates that are insignificant in relation to the effective interest rate of the borrowing; contingent consideration payments made after a business combination; proceeds from the settlement of insurance claims; proceeds from the settlement of corporate-owned life insurance policies including bank-owned life insurance policies; distributions received from equity method investees; beneficial interests in securitization transactions; and separately identifiable cash flows and application of the predominance principle. The guidance is effective for fiscal years beginning after December 15, 2017, and is required to be adopted using a retrospective approach if practicable. We adopted this update effective January 1, 2018, without a material impact on our financial statements or results of operations. In November 2016, the FASB issued authoritative guidance requiring that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The guidance is effective for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years and should be applied using a retrospective transition method to each period presented. We adopted this update effective January 1, 2018, with no material impact to our financial statements or results of operations. Recently issued accounting pronouncements 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. Our current operating leases are predominantly comprised of a limited number of leases for CO 2 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. |
Derivatives, Offsetting Fair Value Amounts | Positive and negative positions with counterparties are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification. |
Nature of operations and summ18
Nature of operations and summary of significant accounting policies (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Accounting Policies [Abstract] | |
Components of accounts receivable | Accounts receivable consisted of the following: March 31, December 31, 2018 2017 Joint interests $ 37,339 $ 29,032 Accrued commodity sales 30,761 26,516 Derivative settlements 10 157 Other 3,008 5,326 Allowance for doubtful accounts (623 ) (668 ) $ 70,495 $ 60,363 |
Components of inventory | Inventories consisted of the following: March 31, December 31, 2018 2017 Equipment inventory $ 6,440 $ 4,163 Commodities 1,202 1,154 Inventory valuation allowance (179 ) (179 ) $ 7,463 $ 5,138 |
Components of unevaluated oil and natural gas properties | The costs of unevaluated oil and natural gas properties consisted of the following: March 31, December 31, 2018 2017 Leasehold acreage $ 527,450 $ 466,711 Capitalized interest 3,655 2,134 Wells and facilities in progress of completion 18,977 13,394 Total unevaluated oil and natural gas properties excluded from amortization $ 550,082 $ 482,239 |
Components of cost reduction initiatives expense | The expense consists of costs for one-time severance and termination benefits in connection with our reductions in force and third party legal and professional services we have engaged to assist in our cost savings initiatives as follows: Successor Predecessor Period from Period from March 22, 2017 January 1, 2017 through through March 31, 2017 March 21, 2017 One-time severance and termination benefits $ 1 $ 608 Professional fees 5 21 Total cost reduction initiatives expense $ 6 $ 629 |
Schedule of Reorganization Items | Reorganization items are as follows: Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through March 31, 2018 March 31, 2017 March 21, 2017 Loss (gain) on the settlement of liabilities subject to compromise $ 48 $ — $ (372,093 ) Fresh start accounting adjustments — — (641,684 ) Professional fees 989 620 18,790 Rejection of employment contracts — — 4,573 Write off unamortized issuance costs on Prior Credit Facility — — 1,687 Total reorganization items $ 1,037 $ 620 $ (988,727 ) |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Earnings Per Share [Abstract] | |
Schedule of Basic and Diluted Earnings Per Share | A reconciliation of the components of basic and diluted EPS is presented below: Three months ended (in thousands, except share and per share data) March 31, 2018 Numerator for basic and diluted earnings per share Net loss $ (11,442 ) Denominator for basic earnings per share Weighted average common shares - Basic for Class A and Class B 45,143,297 Denominator for diluted earnings per share Weighted average common shares - Diluted for Class A and Class B 45,143,297 Earnings per share Basic for Class A and Class B $ (0.25 ) Diluted for Class A and Class B $ (0.25 ) Participating securities excluded from earnings per share calculations Unvested restricted stock awards (2) 1,589,332 Antidilutive securities excluded from earnings per share calculations Warrants (1) 140,023 ________________________________ (1) The warrants to purchase shares of our Class A common stock are antidilutive due to the exercise price exceeding the average price of our Class A shares for the periods presented and due to the net losses we incurred. (2) 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. |
Supplemental disclosures to t20
Supplemental disclosures to the consolidated statements of cash flows (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Supplemental Cash Flow Elements [Abstract] | |
Supplemental disclosures to the consolidated statements of cash flows | Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through March 31, 2018 March 31, 2017 March 21, 2017 Net cash provided by operating activities included: Cash payments for interest $ 2,206 $ 2,768 $ 4,105 Interest capitalized (1,521 ) (54 ) (248 ) Cash payments for interest, net of amounts capitalized $ 685 $ 2,714 $ 3,857 Cash payments for reorganization items $ 410 $ — $ 11,405 Non-cash investing activities included: Asset retirement obligation additions and revisions $ 213 $ — $ 716 Change in accrued oil and gas capital expenditures $ 705 $ — $ 5,387 |
Debt and Capital Leases (Tables
Debt and Capital Leases (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Debt Disclosure [Abstract] | |
Components of debt | As of the dates indicated, long-term debt and capital leases consisted of the following: March 31, December 31, 2018 2017 New Credit Facility $ 206,100 $ 127,100 Real estate mortgage note 9,031 9,177 Capital lease obligations 13,699 14,361 Unamortized debt issuance costs (5,682 ) (5,979 ) Total debt, net 223,148 144,659 Less current portion 3,306 3,273 Total long-term debt, net $ 219,842 $ 141,386 |
Revenue Recognition (Tables)
Revenue Recognition (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Disaggregation Of Revenue [Line Items] | |
Revenue Disaggregated and Reconciles Disaggregated Revenue to Revenue Reported | The following table displays the revenue disaggregated and reconciles the disaggregated revenue to the revenue reported: (in thousands) Three months ended March 31, 2018 Revenues: Oil $ 43,050 Natural gas 8,736 Natural gas liquids 9,591 Gross commodity sales 61,377 Transportation and processing (3,488 ) Net commodity sales 57,889 |
Revenue from Contracts with Customers (“ASC 606”) | |
Disaggregation Of Revenue [Line Items] | |
Summary of Impact of Adoption of Accounting Standards | In accordance with ASC 606, the disclosure of the impact of adoption on our income statement is as follows: Three months ended March 31, 2018 (in thousands) As reported Balances without adoption of ASC 606 Effect of change Revenues Net commodity sales $ 57,889 $ 61,377 $ (3,488 ) Costs and expenses Transportation and processing $ — $ (3,488 ) $ 3,488 |
Derivative instruments (Tables)
Derivative instruments (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Instruments And Hedging Activities Disclosure [Abstract] | |
Summary of derivatives outstanding | The following table summarizes our crude oil derivatives outstanding as of March 31, 2018: Weighted average fixed price per Bbl Period and type of contract Volume MBbls Swaps Purchased puts Sold calls 2018 Swaps 1,576 $ 58.14 $ — $ — Collars 138 $ — $ 50.00 $ 60.50 2019 Swaps 1,312 $ 54.26 $ — $ — 2020 Swaps 1,548 $ 49.54 $ — $ — 2021 Swaps 543 $ 44.34 $ — $ — The following table summarizes our natural gas derivatives outstanding as of March 31, 2018: Period and type of contract Volume BBtu Weighted average fixed price per MMBtu 2018 Swaps 7,911 $ 2.87 2019 Swaps 7,632 $ 2.81 2020 Swaps 3,600 $ 2.77 |
Derivative instruments recorded on the balance sheet at fair value | The estimated fair values of derivative instruments are provided below. The carrying amounts of these instruments are equal to the estimated fair values. As of March 31, 2018 As of December 31, 2017 Assets Liabilities Net value Assets Liabilities Net value Natural gas derivative contracts $ 1,120 $ (671 ) $ 449 $ 1,332 $ (1,054 ) $ 278 Crude oil derivative contracts — (25,832 ) (25,832 ) — (13,404 ) (13,404 ) Total derivative instruments 1,120 (26,503 ) (25,383 ) 1,332 (14,458 ) (13,126 ) Less: Netting adjustments (1) 1,120 (1,120 ) — 1,332 (1,332 ) — Derivative instruments - current — (10,548 ) (10,548 ) — (8,959 ) (8,959 ) Derivative instruments - long-term $ — $ (14,835 ) $ (14,835 ) $ — $ (4,167 ) $ (4,167 ) (1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet. |
Derivative (losses) gains in the consolidated statements of operations | “Derivative (losses) gains” in the consolidated statements of operations are comprised of the following: Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through March 31, 2018 March 31, 2017 March 21, 2017 Change in fair value of commodity price derivatives $ (12,257 ) $ (13,807 ) $ 46,721 Settlements (paid) received on commodity price derivatives (4,244 ) 1,692 1,285 Total derivative (losses) gains $ (16,501 ) $ (12,115 ) $ 48,006 |
Fair value measurements (Tables
Fair value measurements (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value Disclosures [Abstract] | |
Fair value hierarchy for financial instruments measured at fair value on a recurring basis | The fair value hierarchy for our financial assets and liabilities is shown by the following table: As of March 31, 2018 As of December 31, 2017 Derivative assets Derivative liabilities Net assets (liabilities) Derivative assets Derivative liabilities Net assets (liabilities) Significant other observable inputs (Level 2) $ 1,120 $ (25,884 ) $ (24,764 ) $ 1,332 $ (14,163 ) $ (12,831 ) Significant unobservable inputs (Level 3) — (619 ) (619 ) — (295 ) (295 ) Netting adjustments (1) (1,120 ) 1,120 — (1,332 ) 1,332 — $ — $ (25,383 ) $ (25,383 ) $ — $ (13,126 ) $ (13,126 ) (1) Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification. |
Level 3 rollforward | 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: Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through Net derivative assets (liabilities) March 31, 2018 March 31, 2017 March 21, 2017 Beginning balance $ (295 ) $ 715 $ (98 ) Realized and unrealized (losses) gains included in derivative (losses) gains (432 ) (239 ) 813 Settlements paid 108 — — Ending balance $ (619 ) $ 476 $ 715 (Losses) gains relating to instruments still held at the reporting date included in derivative (losses) gains for the period $ (380 ) $ (239 ) $ 813 |
Fair value of other financial instruments | The carrying value and estimated fair value of our debt were as follows: March 31, 2018 December 31, 2017 Level 2 Carrying value (1) Estimated fair value Carrying value (1) Estimated fair value New Credit Facility $ 206,100 $ 206,100 $ 127,100 $ 127,100 Other secured debt 9,031 9,031 9,177 9,177 (1) The carrying value excludes deductions for debt issuance costs. |
Offsetting Assets and Liabilities | 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. Offset in the consolidated balance sheets Gross amounts not offset in the consolidated balance sheets Gross assets (liabilities) Offsetting assets (liabilities) Net assets (liabilities) Derivatives (1) Amounts outstanding under credit facilities (2) Net amount March 31, 2018 Derivative assets $ 1,120 $ (1,120 ) $ — $ — $ — $ — Derivative liabilities (26,503 ) 1,120 (25,383 ) — — (25,383 ) $ (25,383 ) $ — $ (25,383 ) $ — $ — $ (25,383 ) December 31, 2017 Derivative assets $ 1,332 $ (1,332 ) $ — $ — $ — $ — Derivative liabilities (14,458 ) 1,332 (13,126 ) — — (13,126 ) $ (13,126 ) $ — $ (13,126 ) $ — $ — $ (13,126 ) _____________________________________________________ (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. (2) The amount outstanding under our New Credit Facility that is available to offset our net derivative assets due from counterparties that are lenders under our New Credit Facility. |
Asset retirement obligations (T
Asset retirement obligations (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligation Disclosure [Abstract] | |
Asset retirement obligations | The following table provides a summary of our asset retirement obligation activity: Three months ended March 31, 2018 Beginning balance $ 35,990 Liabilities incurred in current period 48 Liabilities settled or disposed in current period (385 ) Revisions in estimated cash flows 165 Accretion expense 532 Ending balance $ 36,350 Less current portion included in accounts payable and accrued liabilities 2,749 Asset retirement obligations, long-term $ 33,601 |
Deferred compensation (Tables)
Deferred compensation (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Summary of amounts related to cash LTIP | A summary of compensation expense for the Cash LTIP is presented below: Successor Predecessor Period from Period from Three months March 22, 2017 January 1, 2017 ended through through March 31, 2018 March 31, 2017 March 21, 2017 Cash LTIP expense (net of amounts capitalized) $ 95 $ 13 $ 5 Cash LTIP payments 17 — 42 |
Stock-based compensation cost | Stock-based compensation expense is as follows for the periods indicated: Successor Predecessor Three months ended March 31, 2018 Period from March 22, 2017 through March 31, 2017 Period from January 1, 2017 through March 21, 2017 Stock-based compensation cost $ 5,580 $ — $ 194 Less: stock-based compensation cost capitalized (957 ) — (39 ) Stock-based compensation expense (credit) $ 4,623 $ — $ 155 Payments for stock-based compensation $ 1,422 $ — $ — |
2017 Management Incentive Plan | |
Rollforward of unvested deferred compensation | A summary of our restricted stock activity pursuant to our MIP is presented below: Time Shares Performance Shares Weighted average grant date fair value Restricted shares Weighted average grant date fair value Restricted shares ($ per share) ($ per share) Unvested and outstanding at January 1, 2018 (1) $ 20.11 1,403,626 $ 20.15 269,476 Granted $ — — $ — — Vested $ — — $ — — Forfeited $ 20.05 (68,540 ) $ 20.05 (15,230 ) Unvested and outstanding at March 31, 2018 $ 20.12 1,335,086 $ 20.17 254,246 _______________________________________________________ (1) The beginning balance of Performance Shares relate to tranches with performance goals for 2018 and 2019. As of March 31, 2018, the goals had not been approved and hence a grant date had not been established and requisite service has not begun. |
Nature of operations and summ27
Nature of operations and summary of significant accounting policies (Reorganization, Fresh Start Accounting and Comparability of Financial Statements to Prior Periods) (Details) | Mar. 21, 2017 |
Maximum | |
Fresh Start Adjustment | |
Fresh start voting share percentage of existing shareholders in emerging entity | 50.00% |
Nature of operations and summ28
Nature of operations and summary of significant accounting policies (Cash and Accounts Receivable) (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Components of accounts receivable | ||
Joint interests | $ 37,339 | $ 29,032 |
Accrued commodity sales | 30,761 | 26,516 |
Derivative settlements | 10 | 157 |
Other | 3,008 | 5,326 |
Allowance for doubtful accounts | (623) | (668) |
Accounts receivable, net | 70,495 | $ 60,363 |
JP Morgan Chase Bank, N.A. | ||
Cash and accounts receivable | ||
Cash held | $ 10,330 |
Nature of operations and summ29
Nature of operations and summary of significant accounting policies (Inventories) (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Energy Related Inventory | ||
Equipment inventory | $ 6,440 | $ 4,163 |
Commodities | 1,202 | 1,154 |
Inventory valuation allowance | (179) | (179) |
Inventories, net | $ 7,463 | $ 5,138 |
Nature of operations and summ30
Nature of operations and summary of significant accounting policies (Unevaluated Oil and Natural Gas Properties) (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Capitalized Costs of Unproved Properties Excluded from Amortization, Cumulative [Abstract] | ||
Leasehold acreage | $ 527,450 | $ 466,711 |
Capitalized interest | 3,655 | 2,134 |
Wells and facilities in progress of completion | 18,977 | 13,394 |
Total unevaluated oil and natural gas properties excluded from amortization | $ 550,082 | $ 482,239 |
Nature of operations and summ31
Nature of operations and summary of significant accounting policies (Income Taxes) (Details) - USD ($) | 3 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2017 | |
Accounting Policies [Abstract] | ||
Federal corporate tax rate | 21.00% | |
Deferred tax benefit | $ 0 | |
Uncertain tax positions | 0 | $ 0 |
Estimated amount of cancellation of indebtedness income | $ 61,000,000 |
Nature of operations and summ32
Nature of operations and summary of significant accounting policies (Loss on Asset Sale) (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Nov. 30, 2017 | Mar. 31, 2018 |
Gain Loss On Sale Of Assets [Line Items] | |||
Loss on sale of assets | $ 0 | $ 1,044 | |
EOR assets | |||
Gain Loss On Sale Of Assets [Line Items] | |||
Loss on sale of assets | $ 25,163 | $ 1,064 |
Nature of operations and summ33
Nature of operations and summary of significant accounting policies (Restructuring) (Details) $ in Thousands | 3 Months Ended |
Mar. 31, 2018USD ($) | |
Accounting Policies [Abstract] | |
Restructuring Charges | $ 425 |
Nature of operations and summ34
Nature of operations and summary of significant accounting policies (Subleases) (Details) $ in Thousands | 1 Months Ended | 3 Months Ended |
Nov. 30, 2017Lease | Mar. 31, 2018USD ($) | |
Accounting Policies [Abstract] | ||
Number of leases under lease agreements | 6 | |
Number of capital leases | 3 | |
Number of operating leases | 3 | |
Operating Leases Income Statement Subleases Costs | $ | $ 403 |
Nature of operations and summ35
Nature of operations and summary of significant accounting policies (Joint Venture) (Details) - Joint Development Agreement $ in Thousands | Sep. 25, 2017USD ($)well |
Joint Venture [Line Items] | |
Percentage of working interest in wells | 15.00% |
Percentage of working interest in wells upon achievement of required internal rate of return | 75.00% |
Canadian | |
Joint Venture [Line Items] | |
Number of joint venture stack wells | 17 |
Garfield | |
Joint Venture [Line Items] | |
Number of joint venture stack wells | 13 |
Bayou City Energy Management, LLC | |
Joint Venture [Line Items] | |
Funded percentage of drilling completion and equipment costs | 100.00% |
Number of joint venture stack wells | 30 |
Percentage of working interest in wells | 85.00% |
Percentage of internal rate of return | 14.00% |
Percentage of working interest in wells upon achievement of required internal rate of return | 25.00% |
Bayou City Energy Management, LLC | Minimum | |
Joint Venture [Line Items] | |
Average well cost caps per gross well | $ | $ 3,400 |
Bayou City Energy Management, LLC | Maximum | |
Joint Venture [Line Items] | |
Average well cost caps per gross well | $ | $ 4,000 |
Nature of operations and summ36
Nature of operations and summary of significant accounting policies (Cost Reduction Initiatives) (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 | Mar. 21, 2017 |
Restructuring Cost and Reserve [Line Items] | |||
Cost reduction initiatives expense | $ 6 | $ 0 | |
Predecessor | |||
Restructuring Cost and Reserve [Line Items] | |||
Cost reduction initiatives expense | $ 629 | ||
One-time Severance and Termination Benefits | |||
Restructuring Cost and Reserve [Line Items] | |||
Cost reduction initiatives expense | 1 | ||
One-time Severance and Termination Benefits | Predecessor | |||
Restructuring Cost and Reserve [Line Items] | |||
Cost reduction initiatives expense | 608 | ||
Professional Fees | |||
Restructuring Cost and Reserve [Line Items] | |||
Cost reduction initiatives expense | $ 5 | ||
Professional Fees | Predecessor | |||
Restructuring Cost and Reserve [Line Items] | |||
Cost reduction initiatives expense | $ 21 |
Nature of operations and summ37
Nature of operations and summary of significant accounting policies (Schedule of reorganization items) (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 | Mar. 21, 2017 |
Restructuring Cost and Reserve [Line Items] | |||
Loss (gain) on the settlement of liabilities subject to compromise | $ 48 | ||
Professional fees | $ 620 | 989 | |
Total reorganization items | $ 620 | $ 1,037 | |
Predecessor | |||
Restructuring Cost and Reserve [Line Items] | |||
Loss (gain) on the settlement of liabilities subject to compromise | $ (372,093) | ||
Fresh start accounting adjustments | (641,684) | ||
Professional fees | 18,790 | ||
Rejection of employment contracts | 4,573 | ||
Write off unamortized issuance costs on Prior Credit Facility | 1,687 | ||
Total reorganization items | $ (988,727) |
Earnings Per Share - Schedule o
Earnings Per Share - Schedule of Basic and Diluted Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 | |
Numerator for basic and diluted earnings per share | |||
Net loss | $ (19,683) | $ (11,442) | |
Denominator for basic earnings per share | |||
Basic for Class A and Class B | 0 | 45,143,297 | |
Denominator for diluted earnings per share | |||
Diluted for Class A and Class B | 0 | 45,143,297 | |
Earnings per share | |||
Basic for Class A and Class B | $ (0.25) | ||
Diluted for Class A and Class B | $ (0.25) | ||
Unvested Restricted Stock Awards | |||
Participating securities excluded from earnings per share calculations | |||
Unvested restricted stock awards | [1] | 1,589,332 | |
Warrants | |||
Antidilutive securities excluded from earnings per share calculations | |||
Warrants | [2] | 140,023 | |
[1] | 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. | ||
[2] | The warrants to purchase shares of our Class A common stock are antidilutive due to the exercise price exceeding the average price of our Class A shares for the periods presented and due to the net losses we incurred. |
Supplemental disclosures to t39
Supplemental disclosures to the consolidated statements of cash flows (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 | Mar. 21, 2017 |
Net cash provided by operating activities included: | |||
Cash payments for interest | $ 2,768 | $ 2,206 | |
Interest capitalized | (54) | (1,521) | |
Cash payments for interest, net of amounts capitalized | $ 2,714 | 685 | |
Cash payments for reorganization items | 410 | ||
Non-cash investing activities included: | |||
Asset retirement obligation additions and revisions | 213 | ||
Change in accrued oil and gas capital expenditures | $ 705 | ||
Predecessor | |||
Net cash provided by operating activities included: | |||
Cash payments for interest | $ 4,105 | ||
Interest capitalized | (248) | ||
Cash payments for interest, net of amounts capitalized | 3,857 | ||
Cash payments for reorganization items | 11,405 | ||
Non-cash investing activities included: | |||
Asset retirement obligation additions and revisions | 716 | ||
Change in accrued oil and gas capital expenditures | $ 5,387 |
Debt and Capital Leases (Compon
Debt and Capital Leases (Components of Debt) (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Debt Instrument [Line Items] | ||
Real estate mortgage note | $ 9,031 | $ 9,177 |
Capital lease obligations | 13,699 | 14,361 |
Unamortized debt issuance costs | (5,682) | (5,979) |
Total debt, net | 223,148 | 144,659 |
Less current portion | 3,306 | 3,273 |
Total long-term debt, net | 219,842 | 141,386 |
New Credit Facility | ||
Debt Instrument [Line Items] | ||
New Credit Facility | $ 206,100 | $ 127,100 |
Debt and Capital Leases (New Cr
Debt and Capital Leases (New Credit Facility) (Details) - New Credit Facility | May 09, 2018USD ($) | Mar. 31, 2018USD ($)qtr |
Line Of Credit Facility [Line Items] | ||
Borrowing base amount | $ 400,000,000 | |
Debt instrument maturity date | Dec. 21, 2022 | |
Availability under the facility | $ 78,072,000 | |
Number of consecutive quarters | qtr | 4 | |
Subsequent Event | ||
Line Of Credit Facility [Line Items] | ||
Borrowing base amount | $ 285,000,000 | |
Secured Debt | ||
Line Of Credit Facility [Line Items] | ||
Secured debt allowed under financial covenants | $ 150,000,000 | |
Secured Debt | Subsequent Event | ||
Line Of Credit Facility [Line Items] | ||
Secured debt allowed under financial covenants | 250,000,000 | |
Minimum | ||
Line Of Credit Facility [Line Items] | ||
Current Ratio covenant | 100.00% | |
Maximum | ||
Line Of Credit Facility [Line Items] | ||
Ratio of debt to EBITDAX | 400.00% | |
Maximum | Subsequent Event | ||
Line Of Credit Facility [Line Items] | ||
Waiver of borrowing base from issuance of unsecured debt | 300,000,000 | |
Unrestricted cash covenant | 50,000,000 | |
Debt Permissible for Equity Related Payments | $ 50,000,000 | |
Adjusted Libo Rate | ||
Line Of Credit Facility [Line Items] | ||
Weighted average interest rate | 4.86% |
Debt and Capital Leases (Capita
Debt and Capital Leases (Capital Leases) (Details) - U.S. Bank - Capital Lease Obligations - USD ($) $ in Thousands | 3 Months Ended | 12 Months Ended |
Mar. 31, 2018 | Dec. 31, 2013 | |
Leases, Capital [Abstract] | ||
Proceeds from sale and leaseback of assets | $ 24,500 | |
Lease term | 84 months | |
Purchase option period | 72 months | |
Implicit interest rate | 3.80% | |
Minimum lease payments | $ 3,181 |
Revenue Recognition - Revenue D
Revenue Recognition - Revenue Disaggregated and Reconciles Disaggregated Revenue to Revenue Reported (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 |
Revenues: | ||
Oil | $ 43,050 | |
Natural gas | 8,736 | |
Natural gas liquids | 9,591 | |
Gross commodity sales | 61,377 | |
Transportation and processing | $ (361) | (3,488) |
Net commodity sales | $ 7,808 | $ 57,889 |
Revenue Recognition - Additiona
Revenue Recognition - Additional information (Details) | 3 Months Ended |
Mar. 31, 2018USD ($) | |
Revenue From Contract With Customer [Abstract] | |
Contract liabilities | $ 0 |
Revenue Recognition - Summary o
Revenue Recognition - Summary of Impact of Adoption of Accounting Standards (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 |
Revenues | ||
Net commodity sales | $ 7,808 | $ 57,889 |
Costs and expenses | ||
Transportation and processing | $ 361 | 3,488 |
Revenue from Contracts with Customers (“ASC 606”) | Balances without Adoption of ASC 606 | ||
Revenues | ||
Net commodity sales | 61,377 | |
Costs and expenses | ||
Transportation and processing | (3,488) | |
Revenue from Contracts with Customers (“ASC 606”) | Effect of Change | ||
Revenues | ||
Net commodity sales | (3,488) | |
Costs and expenses | ||
Transportation and processing | $ 3,488 |
Derivative instruments - Summar
Derivative instruments - Summary of derivatives outstanding (Details) | Mar. 31, 2018MBblsBBtu$ / bbl$ / MMBTU | Feb. 28, 2018$ / bbl |
Swaps | Derivative Maturing in 2018 | ||
Derivative [Line Items] | ||
Weighted average fixed price | 54.80 | |
Swaps | Derivative Maturing in 2018 | Crude Oil Derivative Contracts | ||
Derivative [Line Items] | ||
Volume | MBbls | 1,576 | |
Weighted average fixed price | 58.14 | |
Swaps | Derivative Maturing in 2018 | Natural Gas Derivative Contracts | ||
Derivative [Line Items] | ||
Volume | BBtu | 7,911 | |
Weighted average fixed price | $ / MMBTU | 2.87 | |
Swaps | Derivative Maturing in 2019 | Crude Oil Derivative Contracts | ||
Derivative [Line Items] | ||
Volume | MBbls | 1,312 | |
Weighted average fixed price | 54.26 | |
Swaps | Derivative Maturing in 2019 | Natural Gas Derivative Contracts | ||
Derivative [Line Items] | ||
Volume | BBtu | 7,632 | |
Weighted average fixed price | $ / MMBTU | 2.81 | |
Swaps | Derivative Maturing in 2020 | ||
Derivative [Line Items] | ||
Weighted average fixed price | 46.26 | |
Swaps | Derivative Maturing in 2020 | Crude Oil Derivative Contracts | ||
Derivative [Line Items] | ||
Volume | MBbls | 1,548 | |
Weighted average fixed price | 49.54 | |
Swaps | Derivative Maturing in 2020 | Natural Gas Derivative Contracts | ||
Derivative [Line Items] | ||
Volume | BBtu | 3,600 | |
Weighted average fixed price | $ / MMBTU | 2.77 | |
Swaps | Derivative Maturing in 2021 | ||
Derivative [Line Items] | ||
Weighted average fixed price | 44.34 | |
Swaps | Derivative Maturing in 2021 | Crude Oil Derivative Contracts | ||
Derivative [Line Items] | ||
Volume | MBbls | 543 | |
Weighted average fixed price | 44.34 | |
Collars | Derivative Maturing in 2018 | Crude Oil Derivative Contracts | ||
Derivative [Line Items] | ||
Volume | MBbls | 138 | |
Weighted average fixed price per Bbl, purchased puts | 50 | |
Weighted average fixed price per Bbl, sold calls | 60.50 |
Derivative instruments - Additi
Derivative instruments - Additional information (Details) - Swaps | Feb. 28, 2018$ / bblMBbls |
Derivative Maturing in 2018 | |
Derivative [Line Items] | |
Volume | MBbls | 1,086 |
Weighted average fixed price | 54.80 |
Renegotiated Derivative Maturing in 2018 | |
Derivative [Line Items] | |
Weighted average fixed price | 60 |
Derivative Maturing in 2020 | |
Derivative [Line Items] | |
Volume | MBbls | 543 |
Weighted average fixed price | 46.26 |
Derivative Maturing in 2021 | |
Derivative [Line Items] | |
Volume | MBbls | 543 |
Weighted average fixed price | 44.34 |
Derivative Instruments (Derivat
Derivative Instruments (Derivative instruments recorded on the balance sheet at fair value) (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 | |
Fair value of derivative instruments | |||
Derivative assets, gross | $ 1,120 | $ 1,332 | |
Derivative liabilities, gross | (26,503) | (14,458) | |
Derivative assets (liabilities), net | (25,383) | (13,126) | |
Netting adjustments | [1] | 1,120 | 1,332 |
Derivative Liability, Netting adjustments | [1] | (1,120) | (1,332) |
Current derivative assets, net | 0 | 0 | |
Current derivative liabilities, net | (10,548) | (8,959) | |
Current derivative assets (liabilities), net | (10,548) | (8,959) | |
Long-term derivative assets, net | 0 | 0 | |
Long-term derivative liabilities, net | (14,835) | (4,167) | |
Long-term derivative assets (liabilities), net | (14,835) | (4,167) | |
Natural Gas Derivative Contracts | |||
Fair value of derivative instruments | |||
Derivative assets, gross | 1,120 | 1,332 | |
Derivative liabilities, gross | (671) | (1,054) | |
Derivative assets (liabilities), net | 449 | 278 | |
Crude Oil Derivative Contracts | |||
Fair value of derivative instruments | |||
Derivative liabilities, gross | (25,832) | (13,404) | |
Derivative assets (liabilities), net | $ (25,832) | $ (13,404) | |
[1] | Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted only to the extent that they relate to the same current versus noncurrent classification on the balance sheet. |
Derivative Instruments (Deriv49
Derivative Instruments (Derivative (losses) gains in the consolidated statements of operations) (Details) - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 | Mar. 21, 2017 |
Derivative Gains (Losses) [Line Items] | |||
Change in fair value of commodity price derivatives | $ (13,807) | $ (12,257) | |
Settlements (paid) received on commodity price derivatives | 1,692 | (4,244) | |
Total derivative (losses) gains | $ (12,115) | $ (16,501) | |
Predecessor | |||
Derivative Gains (Losses) [Line Items] | |||
Change in fair value of commodity price derivatives | $ 46,721 | ||
Settlements (paid) received on commodity price derivatives | 1,285 | ||
Total derivative (losses) gains | $ 48,006 |
Fair value measurements (Recurr
Fair value measurements (Recurring Fair Value Measurements) (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 | |
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis | |||
Derivative assets, gross | $ 1,120 | $ 1,332 | |
Derivative liabilities, gross | (26,503) | (14,458) | |
Derivative assets (liabilities), net | (25,383) | (13,126) | |
Derivative assets, amount offset | (1,120) | (1,332) | |
Derivative liabilities, amounts offset | 1,120 | 1,332 | |
Derivative liabilities, net | (25,383) | (13,126) | |
Recurring Fair Value Measurements | |||
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis | |||
Derivative assets (liabilities), net | (25,383) | (13,126) | |
Derivative assets, amount offset | [1] | (1,120) | (1,332) |
Derivative liabilities, amounts offset | [1] | 1,120 | 1,332 |
Derivative assets amount offset (liabilities), net | [1] | 0 | 0 |
Derivative assets, net | 0 | 0 | |
Derivative liabilities, net | (25,383) | (13,126) | |
Recurring Fair Value Measurements | Significant Other Observable Inputs (Level 2) | |||
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis | |||
Derivative assets, gross | 1,120 | 1,332 | |
Derivative liabilities, gross | (25,884) | (14,163) | |
Derivative assets (liabilities), net | (24,764) | (12,831) | |
Recurring Fair Value Measurements | Significant Unobservable Inputs (Level 3) | |||
Fair Value Hierarchy for Financial Instruments Measured at Fair Value on a Recurring Basis | |||
Derivative assets, gross | 0 | 0 | |
Derivative liabilities, gross | (619) | (295) | |
Derivative assets (liabilities), net | $ (619) | $ (295) | |
[1] | Amounts represent the impact of master netting agreements that allow us to net settle positive and negative positions with the same counterparty. Positive and negative positions with counterparties are netted on the balance sheet only to the extent that they relate to the same current versus noncurrent classification. |
Fair value measurements (Level
Fair value measurements (Level 3 Rollforward) (Details) - Recurring Fair Value Measurements - Significant Unobservable Inputs (Level 3) - Derivative - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 | Mar. 21, 2017 |
Level 3 Rollforward | |||
Beginning balance | $ 715 | $ (295) | |
Realized and unrealized (losses) gains included in derivative (losses) gains | (239) | (432) | |
Settlements paid | 0 | 108 | |
Ending balance | 476 | (619) | $ 715 |
(Losses) gains relating to instruments still held at the reporting date included in derivative (losses) gains for the period | (239) | $ (380) | |
Predecessor | |||
Level 3 Rollforward | |||
Beginning balance | $ 715 | (98) | |
Realized and unrealized (losses) gains included in derivative (losses) gains | 813 | ||
Settlements paid | 0 | ||
Ending balance | 715 | ||
(Losses) gains relating to instruments still held at the reporting date included in derivative (losses) gains for the period | $ 813 |
Fair value measurements (Nonrec
Fair value measurements (Nonrecurring Fair Value Measurements) (Details) - Significant Unobservable Inputs (Level 3) - Nonrecurring Fair Value Measurements | Mar. 31, 2017 | Mar. 31, 2018 | Mar. 31, 2017 |
Nonrecurring Fair Value Measurements | |||
Annual inflation rate | 2.26% | 2.30% | |
Minimum | |||
Nonrecurring Fair Value Measurements | |||
Credit-adjusted risk-free interest rate | 5.20% | 6.92% | |
Maximum | |||
Nonrecurring Fair Value Measurements | |||
Credit-adjusted risk-free interest rate | 7.40% | 7.15% |
Fair value measurements (Fair V
Fair value measurements (Fair Value of Other Financial Instruments) (Details) - Significant Other Observable Inputs (Level 2) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 | |
Carrying Value | |||
Fair Value of Other Financial Instruments | |||
New Credit Facility | [1] | $ 206,100 | $ 127,100 |
Estimated Fair Value | |||
Fair Value of Other Financial Instruments | |||
New Credit Facility | 206,100 | 127,100 | |
Secured Debt | Carrying Value | |||
Fair Value of Other Financial Instruments | |||
Other secured debt | [1] | 9,031 | 9,177 |
Secured Debt | Estimated Fair Value | |||
Fair Value of Other Financial Instruments | |||
Other secured debt | $ 9,031 | $ 9,177 | |
[1] | The carrying value excludes deductions for debt issuance costs. |
Fair value measurements (Counte
Fair value measurements (Counterparty Credit Risk) (Details) $ in Thousands | Mar. 31, 2018USD ($)financial_institutions | Dec. 31, 2017USD ($) |
Counterparty Credit Risk | ||
Derivative liabilities subject to acceleration before offsets | $ | $ 26,503 | $ 14,458 |
Concentration of Counterparty Credit Risk | ||
Counterparty Credit Risk | ||
Derivative contracts, number of counterparties | financial_institutions | 4 |
Fair value measurements (Deriva
Fair value measurements (Derivatives Offset in the Consolidated Balance Sheets) (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 | |
Fair Value Disclosures [Abstract] | |||
Derivative assets, gross | $ 1,120 | $ 1,332 | |
Derivative assets, amount offset | (1,120) | (1,332) | |
Derivative assets, not offset | [1] | 0 | 0 |
Credit facility balance available to offset net derivative assets | [2] | 0 | 0 |
Derivative liabilities, gross | (26,503) | (14,458) | |
Derivative liabilities, amounts offset | 1,120 | 1,332 | |
Derivative liabilities | (25,383) | (13,126) | |
Derivative liabilities, not offset | [1] | 0 | 0 |
Credit facility balance available to offset net derivative liabilities | [2] | 0 | 0 |
Derivative liability, net | (25,383) | (13,126) | |
Derivative Asset (Liability), Fair Value, Gross Asset | (25,383) | (13,126) | |
Derivative Asset (Liability), Fair Value, Gross Liability | 0 | 0 | |
Derivative Asset (Liability), Net | (25,383) | (13,126) | |
Derivative liability asset not offset | [1] | 0 | 0 |
Derivative asset (liability), net | $ (25,383) | $ (13,126) | |
[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. | ||
[2] | The amount outstanding under our New Credit Facility that is available to offset our net derivative assets due from counterparties that are lenders under our New Credit Facility |
Asset retirement obligations (D
Asset retirement obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||
Beginning balance | $ 35,990 | |
Liabilities incurred in current period | 48 | |
Liabilities settled or disposed in current period | (385) | |
Revisions in estimated cash flows | 165 | |
Accretion expense | 532 | |
Ending balance | 36,350 | |
Less current portion included in accounts payable and accrued liabilities | 2,749 | |
Asset retirement obligations | $ 33,601 | $ 33,216 |
Deferred compensation (Cash Inc
Deferred compensation (Cash Incentive Plan) (Details) - Cash LTIP - USD ($) $ in Thousands | Mar. 31, 2017 | Mar. 31, 2018 | Mar. 21, 2017 |
Deferred Compensation Arrangement With Individual Excluding Share Based Payments And Postretirement Benefits [Line Items] | |||
Deferred Compensation Arrangement with Individual, Requisite Service Period | 4 years | ||
Cash LTIP expense (net of amounts capitalized) | $ 13 | $ 95 | |
Cash LTIP payments | 17 | ||
Outstanding liability accrued | $ 1,678 | ||
Predecessor | |||
Deferred Compensation Arrangement With Individual Excluding Share Based Payments And Postretirement Benefits [Line Items] | |||
Cash LTIP expense (net of amounts capitalized) | $ 5 | ||
Cash LTIP payments | $ 42 |
Deferred compensation (2017 Man
Deferred compensation (2017 Management Incentive Plan) (Details) | Mar. 21, 2017 | Mar. 31, 2018USD ($)Tranche$ / sharesshares | Dec. 31, 2017$ / shares | Aug. 09, 2017$ / sharesshares | |
Common Class A | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Stock par value | $ 0.01 | $ 0.01 | |||
2017 Management Incentive Plan | Time Shares | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Award vesting period (in years) | 3 years | ||||
2017 Management Incentive Plan | Performance Shares | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Number of tranches | Tranche | 3 | ||||
Share based compensation accrued expense | $ | $ 0 | ||||
2017 Management Incentive Plan | Employees | Time Shares | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Percentage of comprised shares for granted award | 75.00% | ||||
2017 Management Incentive Plan | Employees | Performance Shares | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Percentage of comprised shares for granted award | 25.00% | ||||
2017 Management Incentive Plan | Common Class A | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Stock par value | $ 0.01 | ||||
Shares issued or reserved for issuance | shares | 3,388,832 | ||||
2017 Management Incentive Plan | Common Class A | Time Shares | |||||
Weighted average grant date fair value | |||||
Unvested and outstanding at beginning of period ($ per share) | [1] | $ 20.11 | |||
Granted ($ per share) | 0 | ||||
Vested ($ per share) | 0 | ||||
Forfeited ($ per share) | 20.05 | ||||
Unvested and outstanding at end of period ($ per share) | $ 20.12 | ||||
Weighted average grant date fair value | |||||
Unvested and outstanding at beginning of period (in shares) | shares | [1] | 1,403,626 | |||
Granted (in shares) | shares | 0 | ||||
Vested (in shares) | shares | 0 | ||||
Forfeited (in shares) | shares | (68,540) | ||||
Unvested and outstanding at end of period (in shares) | shares | 1,335,086 | ||||
2017 Management Incentive Plan | Common Class A | Performance Shares | |||||
Weighted average grant date fair value | |||||
Unvested and outstanding at beginning of period ($ per share) | [1] | $ 20.15 | |||
Granted ($ per share) | 0 | ||||
Vested ($ per share) | 0 | ||||
Forfeited ($ per share) | 20.05 | ||||
Unvested and outstanding at end of period ($ per share) | $ 20.17 | ||||
Weighted average grant date fair value | |||||
Unvested and outstanding at beginning of period (in shares) | shares | [1] | 269,476 | |||
Granted (in shares) | shares | 0 | ||||
Vested (in shares) | shares | 0 | ||||
Forfeited (in shares) | shares | (15,230) | ||||
Unvested and outstanding at end of period (in shares) | shares | 254,246 | ||||
Common Stock | 2017 Management Incentive Plan | |||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | |||||
Percentage of shares authorized for issuance | 7.00% | ||||
[1] | The beginning balance of Performance Shares relate to tranches with performance goals for 2018 and 2019. As of March 31, 2018, the goals had not been approved and hence a grant date had not been established and requisite service has not begun. |
Deferred compensation (Stock-ba
Deferred compensation (Stock-based compensation cost) (Details) - USD ($) $ / shares in Units, $ in Thousands | 1 Months Ended | 3 Months Ended | ||
Apr. 30, 2018 | Mar. 31, 2018 | Mar. 21, 2017 | Dec. 31, 2017 | |
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Stock-based compensation cost | $ 5,580 | |||
Less: stock-based compensation cost capitalized | (957) | |||
Stock-based compensation expense (credit) | 4,623 | |||
Payments for stock-based compensation | $ 1,422 | |||
Estimated fair value per share at end of period ($ per share) | $ 17.75 | |||
Aggregate intrinsic value of unvested restricted shares outstanding | $ 28,211 | |||
Repurchase shares for tax withholding | 63,919 | |||
Stock-based compensation costs included in accrued payroll and benefits payable | $ 0 | $ 0 | ||
Unrecognized stock-based compensation cost | $ 12,567 | |||
Weighted-average period for unrecognized compensation cost to be recognized | 1 year 7 months 6 days | |||
Subsequent Event | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Repurchase shares for tax withholding | 181,946 | |||
Repurchase shares for tax withholding, value | $ 3,220 | |||
Predecessor | ||||
Share Based Compensation Arrangement By Share Based Payment Award [Line Items] | ||||
Stock-based compensation cost | $ 194 | |||
Less: stock-based compensation cost capitalized | (39) | |||
Stock-based compensation expense (credit) | $ 155 |
Commitments and Contingencies -
Commitments and Contingencies - Additional information (Details) $ in Thousands | Mar. 26, 2018plaintiffDefendant | Oct. 13, 2017plaintiffDefendant | Apr. 20, 2017USD ($) | Mar. 31, 2017USD ($) | Jan. 17, 2017 | Aug. 15, 2016USD ($) | Mar. 31, 2018USD ($) | Mar. 31, 2017USD ($) | Dec. 31, 2017USD ($) |
Loss Contingency Information About Litigation Matters [Abstract] | |||||||||
Interest paid | $ 2,768 | $ 2,206 | |||||||
Naylor Farms Case Putative Class Action | Pending Litigation | Minimum | |||||||||
Loss Contingency Information About Litigation Matters [Abstract] | |||||||||
Damages sought | $ 150,000 | 5,000 | |||||||
Naylor Farms Case | |||||||||
Loss Contingency Information About Litigation Matters [Abstract] | |||||||||
Minimum percentage of plaintiff in modified class | 60.00% | ||||||||
Naylor Farms Case Actual and Putative Action | Pending Litigation | Minimum | |||||||||
Loss Contingency Information About Litigation Matters [Abstract] | |||||||||
Damages sought | $ 90,000 | ||||||||
West Case Putative Class Action | Pending Litigation | Minimum | |||||||||
Loss Contingency Information About Litigation Matters [Abstract] | |||||||||
Damages sought | 75,000 | ||||||||
James Butler et al. v. Berexco, L.L.C. | |||||||||
Loss Contingency Information About Litigation Matters [Abstract] | |||||||||
Number of individual plaintiffs | plaintiff | 52 | ||||||||
Number of named defendants including parent | Defendant | 26 | ||||||||
Number of unnamed defendants | Defendant | 25 | ||||||||
Lacheverjuan Bennett et al. v. Chaparral Energy, L.L.C., et al. | |||||||||
Loss Contingency Information About Litigation Matters [Abstract] | |||||||||
Number of individual plaintiffs | plaintiff | 27 | ||||||||
Number of named defendants including parent | Defendant | 23 | ||||||||
Number of unnamed defendants | Defendant | 25 | ||||||||
Letter of Credit | |||||||||
Loss Contingency Information About Litigation Matters [Abstract] | |||||||||
Letters of credit outstanding | 828 | $ 828 | |||||||
Interest paid | 0 | $ 0 | |||||||
Proceeds from Letters | $ 0 | $ 0 |