Document and Entity Information
Document and Entity Information - shares | 3 Months Ended | |
Mar. 31, 2018 | May 04, 2018 | |
Document and Entity Information | ||
Document Type | 10-Q | |
Amendment Flag | false | |
Document Period End Date | Mar. 31, 2018 | |
Document Fiscal Year Focus | 2,018 | |
Document Fiscal Period Focus | Q1 | |
Entity Registrant Name | Energy XXI Gulf Coast, Inc. | |
Entity Central Index Key | 1,404,973 | |
Current Fiscal Year End Date | --12-31 | |
Entity Current Reporting Status | Yes | |
Entity Filer Category | Accelerated Filer | |
Entity Common Stock, Shares Outstanding | 33,280,813 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Current Assets | ||
Cash and cash equivalents | $ 112,062 | $ 151,729 |
Accounts receivable | ||
Oil and natural gas sales | 54,662 | 55,598 |
Joint interest billings, net | 5,764 | 6,336 |
Other | 15,290 | 15,726 |
Prepaid expenses and other current assets | 12,147 | 21,602 |
Restricted cash | 6,409 | 6,392 |
Total Current Assets | 206,334 | 257,383 |
Property and Equipment | ||
Oil and natural gas properties, net - full cost method of accounting, including $195.9 million and $200.2 million of unevaluated properties not being amortized at March 31, 2018 and December 31, 2017, respectively | 759,483 | 764,922 |
Other property and equipment, net | 9,157 | 10,120 |
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | 768,640 | 775,042 |
Other Assets | ||
Restricted cash | 25,758 | 25,712 |
Other assets | 24,303 | 18,845 |
Total Other Assets | 50,061 | 44,557 |
Total Assets | 1,025,035 | 1,076,982 |
Current Liabilities | ||
Accounts payable | 66,769 | 85,122 |
Accrued liabilities | 41,332 | 45,494 |
Asset retirement obligations | 53,415 | 51,398 |
Derivative financial instruments | 32,354 | 32,567 |
Current maturities of long-term debt | 5,571 | 21 |
Total Current Liabilities | 199,441 | 214,602 |
Long-term debt, less current maturities | 58,407 | 73,952 |
Asset retirement obligations | 620,105 | 613,453 |
Other liabilities | 12,673 | 10,783 |
Total Liabilities | 890,626 | 912,790 |
Commitments and Contingencies (Note 13) | ||
Stockholders' Equity | ||
Preferred stock, $0.01 par value, 10,000,000 shares authorized and no shares outstanding at March 31, 2018 and December 31, 2017 | ||
Common stock, $0.01 par value, 100,000,000 shares authorized and 33,268,478 and 33,254,963 shares issued and outstanding at March 31, 2018 and December 31, 2017 respectively | 333 | 333 |
Additional paid-in capital | 913,828 | 911,144 |
Accumulated deficit | (779,752) | (747,285) |
Total Stockholders' Equity | 134,409 | 164,192 |
Total Liabilities and Stockholders' Equity | $ 1,025,035 | $ 1,076,982 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions | Mar. 31, 2018 | Dec. 31, 2017 |
Consolidated Balance Sheets | ||
Oil and natural gas properties, net - full cost method of accounting, unevaluated properties not being amortized | $ 195.9 | $ 200.2 |
Preferred stock, par value | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 |
Preferred stock, shares outstanding | 0 | 0 |
Common stock, par value | $ 0.01 | $ 0.01 |
Common stock, shares authorized | 100,000,000 | 100,000,000 |
Common stock, shares issued | 33,268,478 | 33,254,963 |
Common stock, shares outstanding | 33,268,478 | 33,254,963 |
Consolidated Statements of Oper
Consolidated Statements of Operations - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Revenues | ||
Oil sales | $ 123,788 | $ 133,793 |
Natural gas liquids sales | 1,343 | 2,227 |
Natural gas sales | 8,382 | 18,368 |
Other revenue | 1,492 | |
(Loss) gain on derivative financial instruments | (12,834) | 3,698 |
Total Revenues | 122,171 | 158,086 |
Costs and Expenses | ||
Lease operating | 82,022 | 77,267 |
Production taxes | 1,206 | 239 |
Gathering and transportation | 4,056 | 11,222 |
Pipeline facility fee | 10,494 | 10,494 |
Depreciation, depletion and amortization | 27,411 | 41,896 |
Accretion of asset retirement obligations | 11,118 | 13,081 |
Impairment of oil and natural gas properties | 40,774 | |
General and administrative expense | 15,132 | 21,604 |
Reorganization items | 236 | 2,244 |
Total Costs and Expenses | 151,675 | 218,821 |
Operating Loss | (29,504) | (60,735) |
Other Income (Expense) | ||
Other income, net | 143 | 22 |
Interest expense | (3,694) | (3,834) |
Total Other Expense, net | (3,551) | (3,812) |
Loss Before Income Taxes | (33,055) | (64,547) |
Net Loss | $ (33,055) | $ (64,547) |
Loss per Share | ||
Basic and Diluted (in dollars per share) | $ (0.99) | $ (1.94) |
Weighted Average Number of Common Shares Outstanding | ||
Basic and Diluted (in shares) | 33,296 | 33,228 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Cash Flows From Operating Activities | ||
Net loss | $ (33,055) | $ (64,547) |
Adjustments to reconcile net loss to net cash provided by (used in) operating activities: | ||
Depreciation, depletion and amortization | 27,411 | 41,896 |
Impairment of oil and natural gas properties | 40,774 | |
Change in fair value of derivative financial instruments | (213) | (3,409) |
Accretion of asset retirement obligations | 11,118 | 13,081 |
Amortization of debt issuance costs | 5 | |
Deferred rent | 1,930 | 2,015 |
Stock-based compensation | 2,758 | 852 |
Changes in operating assets and liabilities | ||
Accounts receivable | 1,944 | 15,555 |
Prepaid expenses and other assets | 3,680 | 6,969 |
Settlement of asset retirement obligations | (18,804) | (9,316) |
Accounts payable, accrued liabilities and other | (13,574) | (57,572) |
Net Cash Used in Operating Activities | (16,800) | (13,702) |
Cash Flows from Investing Activities | ||
Capital expenditures | (12,977) | (19,105) |
Insurance payments received | 2,051 | |
Proceeds from the sale of other property and equipment | 250 | 1,269 |
Net Cash Used in Investing Activities | (12,727) | (15,785) |
Cash Flows from Financing Activities | ||
Payments on long-term debt | (10,002) | (602) |
Other | (75) | |
Net Cash Used in Financing Activities | (10,077) | (602) |
Net Decrease in Cash, Cash Equivalents and Restricted Cash | (39,604) | (30,089) |
Cash, Cash Equivalents and Restricted Cash, beginning of period | 183,833 | 223,288 |
Cash, Cash Equivalents and Restricted Cash, end of period | $ 144,229 | $ 193,199 |
Organization
Organization | 3 Months Ended |
Mar. 31, 2018 | |
Organization | |
Organization | Note 1 — Organization Nature of Operations Energy XXI Gulf Coast, Inc. (“EGC” or the “Company”) was formed in December 2016 after emerging from a voluntary reorganization under chapter 11 proceedings as the restructured successor of Energy XXI Ltd (“EXXI Ltd”). We are headquartered in Houston, Texas, and engage in the development, exploitation, and operation of oil and natural gas properties primarily offshore in the GoM Shelf, which is an area in less than 1,000 feet of water, and also onshore in Louisiana and Texas. We own and operate nine of the largest GoM Shelf oil fields ranked by total cumulative oil production to date and utilize various techniques to increase the recovery factor and thus increase the total oil recovered. |
Summary of Significant Accounti
Summary of Significant Accounting Policies and Recent Accounting Pronouncements | 3 Months Ended |
Mar. 31, 2018 | |
Summary of Significant Accounting Policies and Recent Accounting Pronouncements | |
Summary of Significant Accounting Policies and Recent Accounting Pronouncements | Note 2 – Summary of Significant Accounting Policies and Recent Accounting Pronouncements Principles of Consolidation and Reporting. The accompanying consolidated financial statements on March 31, 2018 include the accounts of EGC and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. The consolidated financial statements for the prior period include certain reclassifications to conform to the current presentation. Those reclassifications did not have any impact on the previously reported consolidated result of operations or cash flows. Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value estimates used in fresh start accounting; accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; asset retirement obligations; deferred income taxes; valuation of derivative financial instruments; among others. Accordingly, our accounting estimates require the exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material. Interim Financial Statements. The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10‑Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the 2017 Annual Report. Recent Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014‑09, Revenue from Contracts with Customers (“ASU 2014‑09”), as a new Accounting Standards Codification (ASC) Topic, ASC 606. ASU 2014‑09 is effective for us beginning in the first quarter of 2018. In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC guidance in the related ASC, including guidance related to the use of the “entitlements” method of revenue recognition used by the Company. The Company adopted ASC 606 effective January 1, 2018, which replaces previous revenue recognition requirements under FASB ASC Topic 605 – Revenue Recognition (“ASC 605”). The standard was adopted using the modified retrospective approach which requires the Company to recognize in retained earnings at the date of adoption the cumulative effect of the application of ASC 606 to all existing revenue contracts which were not substantially complete as of January 1, 2018. T he Company has elected the contract modification practical expedient which allows the Company to reflect the aggregate effect of all modifications prior to the date of adoption when applying ASC 606. Although the adoption of ASC 606 did not have an impact on the Company’s net loss or cash flows, it did result in the reclassification of certain fees received under pipeline gathering and transportation and pipeline tariff agreements that were previously included in oil sales to other revenue i n the consolidated statements of operations. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as lease operating expense and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered. The Company receives payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable, oil and natural gas sales in the consolidated balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. The Company has elected to utilize the practical expedient in ASC 606 that states the 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. Under our contracts, each monthly delivery of product 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. The Company previously utilized the entitlements method to account for natural gas imbalances, which is no longer applicable under ASC 606. The impact to the financial statements resulting from this change in accounting for our natural gas imbalances was not significant. In February 2016, the FASB issued ASU No. 2016‑02, Leases ( “ ASU 2016‑02”), to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB amended the FASB Accounting Standards Codification and created Topic 842, Leases . The guidance in this ASU supersedes Topic 840, Leases. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In the normal course of business, we enter into lease agreements to support our operations. We are evaluating the provisions of ASU 2016‑02 to determine the quantitative effects it will have on our consolidated financial statements and related disclosures. We believe the adoption and implementation of this ASU will have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. In June 2016, the FASB issued ASU No. 2016‑13, Credit Losses, Measurement of Credit Losses on Financial Instruments (“ASU 2016‑13”). ASU 2016‑13 significantly changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace today’s incurred loss approach with an expected loss model for instruments measured at amortized cost. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. This ASU is effective for public entities for annual and interim periods beginning after December 15, 2019. Early adoption is permitted for all entities for annual periods beginning after December 15, 2018, and interim periods therein. We have not yet determined the effect of this standard on our consolidated financial position, results of operations or cash flows. In August 2016, the FASB issued ASU No. 2016‑15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016‑15”). ASU 2016‑15 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. Our adoption of ASU 2016‑15 on January 1, 2018 using the retrospective transition method had no effect on our consolidated financial position, results of operations or cash flows other than presentation. In November 2016, the FASB issued ASU No. 2016‑18 , Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016‑18). ASU 2016‑18 requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. Our adoption of ASU 2016‑18 on January 1, 2018 had no effect on our consolidated financial position, results of operations or cash flows other than presentation. |
Property and Equipment
Property and Equipment | 3 Months Ended |
Mar. 31, 2018 | |
Property and Equipment | |
Property and Equipment | Note 3 – Property and Equipment Property and equipment consists of the following ( in thousands ): As of March 31, As of December 31, 2018 2017 Oil and natural gas properties - full cost method of accounting Proved properties $ 1,328,528 $ 1,307,009 Less: accumulated depreciation, depletion, amortization and impairment (764,952) (742,286) Proved properties, net 563,576 564,723 Unevaluated properties 195,907 200,199 Oil and natural gas properties, net 759,483 764,922 Other property and equipment 13,902 13,780 Less: accumulated depreciation and impairment (4,745) (3,660) Other property and equipment, net 9,157 10,120 Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 768,640 $ 775,042 Under the full cost method of accounting, at the end of each financial reporting period, we compare the present value of estimated future net cash flows from proved reserves (computed using the unweighted arithmetic average of the first-day-of-the-month historical price, net of applicable differentials, for each month within the previous 12‑month period discounted at 10%, plus the lower of cost or fair market value of unevaluated properties and excluding cash flows related to estimated abandonment costs associated with developed properties) to the net capitalized costs of oil and natural gas properties, net of related deferred income taxes. We refer to this comparison as a “ceiling test.” If the net capitalized costs of these oil and natural gas properties exceed the estimated discounted future net cash flows, we are required to write-down the value of our oil and natural gas properties to the amount of the discounted cash flows. For the three months ended March 31, 2018, we did not incur any impairment to our oil and natural gas properties and for the three months ended March 31, 2017, we recorded impairment to oil and natural gas properties of $40.8 million as a result of the decrease in proved reserves and PV‑10 value as of March 31, 2017 relative to the estimated reserves prepared by our internal reservoir engineers as of December 31, 2016. Costs associated with unevaluated properties are transferred to evaluated properties either (i) ratably over a period of the related field’s life, or (ii) upon determination as to whether there are any proved reserves related to the unevaluated properties or the costs are impaired or capital costs associated with the development of these properties will not be available. For the three months ended March 31, 2018, the costs associated with unevaluated properties decreased by $4.3 million, of which $ 2.2 million was the ratable amortization to the evaluated properties and the remaining $ 2.1 million was transferred to evaluated properties due to impairment. |
Long-Term Debt
Long-Term Debt | 3 Months Ended |
Mar. 31, 2018 | |
Long-Term Debt | |
Long-Term Debt | Note 4 – Long-Term Debt As of March 31, 2018 and December 31, 2017 our outstanding debt consisted of the following ( in thousands ): Successor March 31, 2018 December 31, 2017 Exit Facility $ 63,996 $ 73,996 Capital lease obligations 21 21 Total debt 64,017 74,017 Less: debt issue costs 39 44 Less: current maturities 5,571 21 Total long-term debt $ 58,407 $ 73,952 Exit Facility On December 30, 2016, the Company entered into a secured Exit Facility, which matures on December 30, 2019. The Exit Facility, as amended, is secured by mortgages on at least 90% of the value of our and our subsidiary guarantors’ proved developed producing reserves as well as our total proved reserves. The Exit Facility consists of two facilities: (i) a term loan facility (the “Exit Term Loan”) and (ii) a revolving credit facility (the “Exit Revolving Facility”) for the making of revolving loans and the issuance of letters of credit. The Exit Facility is guaranteed by substantially all of the wholly-owned subsidiaries of the Company, subject to customary exceptions, and is secured by first priority security interests on substantially all assets of each guarantor. Under the Exit Facility, the borrower will not declare or make a restricted payment, or make any deposit for any restricted payment. Restricted payments include declaration or payment of dividends. The Company must make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit if a reduction in the revolving credit capacity would cause the revolving credit exposure to exceed the revolving credit capacity. On or after the determination of the borrowing base, the Company must also make a mandatory prepayment of the revolving loans and, if necessary, cash collateralize the outstanding letters of credit not in favor of ExxonMobil if a borrowing base deficiency arises. The Exit Facility contains covenants and events of default customary for reserve-based lending facilities. In addition, for each fiscal quarter ending on and after March 31, 2018, the Company must maintain a Current Ratio (as defined in the Exit Facility) of no less than 1.00 to 1.00 and a First Lien Leverage Ratio (as defined in the Exit Facility) of no greater than 4.00 to 1.00 calculated on a trailing four quarter basis. On March 29, 2018, we prepaid $10 million outstanding under the Exit Term Loan. Due to a decline in our estimated trailing twelve-month EBITDA calculation for the twelve-month period ending June 30, 2018, we may be required to prepay additional amounts of our outstanding Exit Term Loan in order to prevent a breach of the First Lien Leverage Ratio, and such a prepayment could adversely affect our liquidity. Under those circumstances, we would also discuss a covenant waiver with our banking group to remain in compliance with that ratio. Furthermore, for each fiscal quarter ending on and after March 31, 2018, if the Asset Coverage Ratio (as defined in the Exit Facility) is less than 1.50 to 1.00, the Company must make a mandatory prepayment of the Exit Term Loan in an amount equal to the lesser of (i) 7.5% of the aggregate outstanding principal amount of the Exit Term Loan on December 30, 2016 and (ii) the then outstanding principal amount of the Exit Term Loan. Based upon the Company’s current expectations with respect to its capital resources, capital expenditures, results from operations and commodity prices, the Company believes that it is reasonably likely that it will be required to make a mandatory prepayment with respect to each fiscal quarter ending on and after March 31, 2018. In that case, the first such payment of approximately $5.55 million will be paid during the fiscal quarter ending June 30, 2018. Any such mandatory prepayment would not, in and of itself, constitute a default under the Exit Facility. Unused credit capacity under the Exit Revolving Facility will accrue a commitment fee of 0.50% payable quarterly in arrears. Interest on the outstanding amount of the Exit Term Loan, at the Company’s option, will accrue at an interest rate equal to either: (i) the Alternative Base Rate (as defined in the Exit Facility) plus 3.5% per annum or (ii) the one-month LIBO Rate (as defined in the Exit Facility) plus 4.5% per annum. Interest on the Exit Term Loan bearing interest at the Alternative Base Rate will be payable quarterly; interest on the Exit Term Loan bearing interest at the LIBO Rate will be payable monthly. Interest on the outstanding amount of revolving loans borrowed under the Exit Revolving Facility, at the Company’s option, will accrue at an interest rate equal to either (i) the Alternative Base Rate plus 3.5% per annum or (ii) the one, three or six month LIBO Rate plus 4.5% per annum. Interest on revolving loans that bear interest at the Alternative Base Rate will be payable quarterly; interest on revolving loans that bear interest at the LIBO Rate will be payable at the end of each interest period or, if an interest period exceeds three months, at the end of every three months. The stated amount of each letter of credit issued under the Exit Revolving Facility accrues fees at the rate of 4.5% per annum. There is an issuance fee of 0.25% per annum charged on the stated amount of each letter of credit issued after December 30, 2016. We currently have $12.5 million available for borrowing, under specific circumstances, as revolving loans subject to a maximum for all such loans of (i) $25 million prior to the date the borrowing base is initially determined and (ii) the borrowing base, on and after the date the borrowing base is initially determined. The borrowing base will be initially determined at a date elected by the Company, and will be redetermined semi-annually thereafter. Currently, the Company has not elected a date for the initial borrowing base determination. As of March 31, 2018, we had approximately $64 million in borrowings and $20 1.5 million in letters of credit issued under the Exit Facility. |
Asset Retirement Obligations
Asset Retirement Obligations | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligations | |
Asset Retirement Obligations | Note 5 – Asset Retirement Obligations The following table describes the changes to our asset retirement obligations ( in thousands ): Balance as of December 31, 2017 $ 664,851 Liabilities incurred 8,722 Liabilities settled (18,804) Revisions 7,633 Accretion expense 11,118 Total balance as of March 31, 2018 673,520 Less: current portion 53,415 Long-term portion as of March 31, 2018 $ 620,105 |
Derivative Financial Instrument
Derivative Financial Instruments | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Financial Instruments | |
Derivative Financial Instruments | Note 6 – Derivative Financial Instruments We enter into derivative transactions to reduce exposure to fluctuations in the price of crude oil and natural gas with multiple investment-grade rated counterparties, primarily financial institutions, to reduce the concentration of exposure to any individual counterparty. We have historically used various instruments, including financially settled crude oil and natural gas puts, put spreads, swaps, costless collars and three-way collars in our derivative portfolio. With a costless collar, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the floor price of the collar, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the cap price for the collar. In a fixed price swap contract, the counterparty is required to make a payment to us if the settlement price for any settlement period is below the swap fixed price, and we are required to make a payment to the counterparty if the settlement price for any settlement period is above the swap fixed price. Derivative financial instruments are recorded at fair value and included as either assets or liabilities in the accompanying consolidated balance sheets. Any gains or losses resulting from changes in fair value of our outstanding derivative financial instruments and from the settlement of derivative financial instruments are recognized in earnings and included in (loss) gain on derivative financial instruments as a component of revenues in the accompanying consolidated statements of operations. Most of our crude oil production is sold at Heavy Louisiana Sweet. We have historically included contracts indexed to NYMEX-WTI, ICE Brent futures and Argus-LLS futures in our derivative portfolio to closely align and manage our exposure to the associated price risk. The energy markets have historically been very volatile, and there can be no assurances that crude oil and natural gas prices will not be subject to wide fluctuations in the future. While the use of derivative arrangements helps to limit the downside risk of adverse price movements, they may also limit future gains from favorable price movements. As of March 31, 2018, we had the following open crude oil derivative positions: Weighted Average Type of Volumes Contract Price Remaining Contract Term Contract Index (MBbls) Swaps April 2018 - December 2018 Swaps NYMEX-WTI $ 50.68 April 2018 - June 2018 Swaps Argus-LLS $ 55.45 April 2018 - June 2018 Swaps ICE Brent $ 56.59 The fair values of derivative instruments in our consolidated balance sheets were as follows ( in thousands ): Asset Derivative Instruments Liability Derivative Instruments March 31, 2018 December 31, 2017 March 31, 2018 December 31, 2017 Balance Fair Value Balance Fair Value Balance Fair Value Balance Fair Value Derivative financial instruments Current $ - Current $ - Current $ 32,354 Current $ 32,567 Non- - Non- - Non- - Non- - Total gross derivative financial instruments subject to enforceable master netting agreement - - 32,354 32,567 Derivative financial instruments Current - Current - Current - Current - Non- - Non- - Non- - Non- - Gross amounts offset in Balance Sheets - - - - Net amounts presented in Balance Sheets Current - Current - Current 32,354 Current 32,567 Non- - Non- - Non- - Non- - $ - $ - $ 32,354 $ 32,567 The following table presents information about the components of the (loss) gain on derivative financial instruments ( in thousands ). Three Months Ended Three Months Ended March 31, March 31, (Loss) gain on derivative financial instruments 2018 2017 Cash settlements $ (13,047) $ 289 Non-cash gain in fair value 213 3,409 Total (loss) gain on derivative financial instruments $ (12,834) $ 3,698 We monitor the creditworthiness of our counterparties who are also a part of our bank lending group. However, we are not able to predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Possible actions would be to transfer our position to another counterparty or request a voluntary termination of the derivative contracts resulting in a cash settlement. Should one of our financial counterparties not perform, we may not realize the benefit of some of our derivative instruments under lower commodity prices and could incur a loss. As of March 31, 2018, we had no collateral deposits with our counterparties. |
Income Taxes
Income Taxes | 3 Months Ended |
Mar. 31, 2018 | |
Income Taxes | |
Income Taxes | Note 7 – Income Taxes No cash income taxes were paid during the period ended March 31, 2018, and, based upon current commodity pricing and planned development activity, no cash income taxes are expected to be paid or owed for the year ending December 31, 2018. We have estimated our effective income tax rate for the year to be zero, as we are forecasting a pre-tax loss at this time. We do not believe that our net deferred tax assets are realizable in the future on a more-likely-than-not basis at this time; as such, we have increased our valuation allowance by $7 million in the quarter ended March 31, 2018 to reflect the tax effect of this loss. This $7 million first quarter valuation allowance increase, when coupled with the $306 million valuation allowance at December 31, 2017, results in a valuation allowance of $313 million at March 31, 2018. We made no changes during the period to our deferred tax assets or valuation allowance related to the Tax Cuts and Jobs Act of 2017. |
Stockholders' Equity
Stockholders' Equity | 3 Months Ended |
Mar. 31, 2018 | |
Stockholders' Equity | |
Stockholders' Equity | Note 8 – Stockholders’ Equity Under our certificate of incorporation, the total number of all shares of capital stock that we are authorized to issue is 110 million shares, consisting of 100 million shares of the Company’s common stock, par value $0.01 per share, and 10 million shares of preferred stock, par value $0.01 per share. For the three months ended March 31, 2018, we issued 13,515 shares of our common stock upon vesting of restricted stock units and as of March 31, 2018, we had 33,268,478 shares of common stock and 2,119,889 warrants outstanding. |
Supplemental Cash Flow Informat
Supplemental Cash Flow Information | 3 Months Ended |
Mar. 31, 2018 | |
Supplemental Cash Flow Information | |
Supplemental Cash Flow Information | Note 9 – Supplemental Cash Flow Information The following table presents our supplemental cash flow information ( in thousands ): Three Months Ended Three Months Ended March 31, March 31, 2018 2017 Cash paid for interest $ 3,560 $ 2,817 Cash paid for income taxes - - The following table presents our non-cash investing and financing activities ( in thousands ): Three Months Ended Three Months Ended March 31, March 31, 2018 2017 Changes in capital expenditures and accrued liabilities or accounts payable $ (8,076) $ (2,660) Changes in asset retirement obligations 16,355 (133,434) The following table presents the reconciliation of cash, cash equivalents and restricted cash as presented on the consolidated statement of cash flows (in thousands) : As of March 31, December 31, March 31, 2018 2017 2017 Cash and cash equivalents $ 112,062 $ 151,729 $ 160,479 Restricted cash, current 6,409 6,392 7,114 Restricted cash, long term 25,758 25,712 25,606 Total Cash, cash equivalents and restricted cash $ 144,229 $ 183,833 $ 193,199 |
Employee Benefit Plans
Employee Benefit Plans | 3 Months Ended |
Mar. 31, 2018 | |
Employee Benefit Plans | |
Employee Benefit Plans | Note 10 – Employee Benefit Plans On December 30, 2016, the Company entered into the Energy XXI Gulf Coast, Inc. 2016 Long Term Incentive Plan (the “2016 LTIP”), which is a comprehensive equity-based award plan as part of the compensation for the Company’s officers, directors, employees and consultants (the “Service Providers”). The total number of shares of our common stock reserved and available for delivery with respect to awards under the 2016 LTIP was 1,859,552 shares (or 5% of the total new equity). The compensation committee (the “Committee”) of the board of directors of the Company (the “Board”) generally administers the 2016 LTIP and determines the types of equity based awards (which may include stock option, stock appreciation rights, restricted stock, restricted stock units, bonus stock awards, performance awards, other stock based awards or cash awards) and the terms and conditions (including vesting and forfeiture restrictions) of such awards. Awards under the 2016 LTIP are awarded to the Service Providers selected in the discretion of the Committee; provided, however, that 3% of the 5% total new equity on a fully diluted basis reserved under the 2016 LTIP must be allocated no later than 120 days after December 30, 2016. As of April 29, 2017, the 3% of total new equity had been allocated by the Board. Under the 2016 LTIP, stock options are issued with an exercise price that is not less than the fair market value of our common stock on the date of grant and expire 10 years from the grant date. Stock options that have been granted to date generally vest ratably over a three-year period. The fair value of each stock option granted is estimated on the date of grant using a Black-Scholes-Merton option valuation model that uses assumptions related to expected term, expected volatility, risk free rate and dividend yield. As of March 31, 2018, we had 285,105 unvested stock options and $ 1.2 million in unrecognized compensation cost related to unvested stock options. Under the 2016 LTIP, restricted stock units may be granted as approved by the Committee. To date, the restricted stock units granted by the Committee have a vesting date up to three years from the date of grant and each restricted stock unit represents a right to receive one share of our common stock. During the three months ended March 31, 2018, we granted 7 96,967 restricted stock units at a weighted average price of $ 6.12 per restricted stock unit. As of March 31, 2018, we had 1,316,579 unvested restricted stock units and $1 0.1 million in unrecognized compensation cost related to unvested restricted stock units. In order to retain key employees and attract new employees with the experience and skill sets that fit our culture and corporate strategy, the Board approved the Energy XXI Gulf Coast, Inc. 2018 Long Term Incentive Plan (the “2018 LTIP”) on April 11, 2018, subject to stockholder approval at the 2018 annual meeting of stockholders to be held on May 17, 2018. If approved by the stockholders, the number of shares of common stock available for awards under the 2018 LTIP would be (i) 1,860,000 plus (ii) the number of shares remaining available for award under the 2016 LTIP on the date of the 2018 annual meeting. As of April 11, 2018, there were 37,835 shares remaining available for award under the 2016 LTIP. |
Loss per Share
Loss per Share | 3 Months Ended |
Mar. 31, 2018 | |
Loss per Share | |
Loss per Share | Note 11 — Loss per Share Basic loss per share of common stock is computed by dividing net loss attributable to common stockholders by the weighted average number of shares of common stock outstanding during the period. Except when the effect would be anti-dilutive, the diluted earnings per share calculation includes the impact of restricted stock, stock options and other common stock equivalents. The following table sets forth the calculation of basic and diluted loss per share (“EPS”) ( in thousands, except per share data ): Three Months Ended Three Months Ended March 31, March 31, 2018 2017 Net loss $ (33,055) $ (64,547) Weighted average shares outstanding for basic EPS 33,296 33,228 Add dilutive securities - - Weighted average shares outstanding for diluted EPS 33,296 33,228 Loss per share Basic and Diluted $ (0.99) $ (1.94) The Company’s restricted stock units granted to the members of the Board which are vested but not yet issued are treated as outstanding for basic loss per share calculations since these shares are entitled to participate in dividends declared on common shares, if any, and undistributed earnings. As participating securities, the shares of restricted stock are included in the calculation of basic EPS using the two-class method. For the three months ended March 31, 2018 and 2017, no net loss was allocated to the participating securities. For the three months ended March 31, 2018 and 2017, 3,665,257 and 1,206,765 common stock equivalents, respectively, were excluded from the diluted average shares calculation due to an anti-dilutive effect. |
Commitments and Contingencies
Commitments and Contingencies | 3 Months Ended |
Mar. 31, 2018 | |
Commitments and Contingencies | |
Commitments and Contingencies | Note 12 — Commitments and Contingencies Litigation. We are involved in various legal proceedings and claims, which arise in the ordinary course of our business. We do not believe the ultimate resolution of any such actions will have a material effect on our consolidated financial position, results of operations or cash flows. Letters of Credit and Performance Bonds. As of March 31, 2018, we had approximately $3 25.8 million of performance bonds outstanding and $200 million in letters of credit issued to ExxonMobil relating to assets in the Gulf of Mexico. In April 2015, the Predecessor received letters from the BOEM stating that certain of its subsidiaries no longer qualified for waiver of certain supplemental bonding requirements for potential offshore decommissioning, plugging and abandonment liabilities. As of March 31, 2018, approximately $174.1 million of our performance bonds are lease and/or area bonds issued to the BOEM, to which the BOEM has access to ensure our commitment to comply with the terms and conditions of those leases. As of March 31, 2018, we also maintained approximately $15 1.7 million in performance bonds issued to third party assignors including certain state regulatory bodies for eventual decommissioning of certain wells and facilities. As of March 31, 2018, we had $ 47.9 million in cash collateral provided to surety companies associated with the bonding requirements of the BOEM and third party assignors. To address the supplemental bonding and other financial assurance concerns expressed to us by the BOEM in April 2015 and thereafter, the Predecessor submitted a long-term financial assurance plan (the “Long-Term Plan”) to the agency. Further, the Predecessor submitted a proposed plan amendment on June 28, 2016 that would revise the executed Long-Term Plan (the “Proposed Plan Amendment”). We continue to work with the BOEM under the Long-Term Plan and the Proposed Plan Amendment. Drilling Rig Commitments. As of March 31, 2018, we have approximately $ 10.7 million committed under two rig contracts for drillwells, rig recompletions and plugging and abandonment activities. The contracts’ terms range from February 23, 2018 through September 12, 2018. Other. We maintain restricted escrow funds as required by certain contractual arrangements. As of March 31, 2018, our restricted cash primarily related to $25. 7 million in cash collateral associated with our bonding requirements and approximately $6.1 million in a trust for future plugging, abandonment and other decommissioning costs related to the East Bay field that was sold to Whitney Oil & Gas, LLC and Trimont Energy (NOW), LLC on June 30, 2015. Funds held in trust will be transferred to the buyers of our interests in that field. We and our oil and natural gas joint interest owners are subject to periodic audits of the joint interest accounts for leases in which we participate and/or operate. As a result of these joint interest audits, amounts payable or receivable by us for costs incurred or revenue distributed by the operator or by us on a lease may be adjusted, resulting in adjustments to our net costs or revenues and related cash flows. When they occur, these adjustments are recorded in the current period, which generally is one or more years after the related cost or revenue was incurred or recognized by the joint account. We do not believe any such adjustments will be material. |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value of Financial Instruments | |
Fair Value | Note 13 — Fair Value of Financial Instruments Certain assets and liabilities are measured at fair value on a recurring basis in our consolidated balance sheets. Valuation techniques are generally classified into three categories: the market approach; the income approach; and the cost approach. The selection and application of one or more of these techniques requires significant judgment and is primarily dependent upon the characteristics of the asset or liability, the principal (or most advantageous) market in which participants would transact for the asset or liability and the quality and availability of inputs. Inputs to valuation techniques are classified as either observable or unobservable within the following hierarchy: · Level 1 – quoted prices in active markets for identical assets or liabilities. · Level 2 – inputs other than quoted prices that are observable for an asset or liability. These include: quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability; and inputs that are derived principally from or corroborated by observable market data by correlation or other means (market-corroborated inputs). · Level 3 – unobservable inputs that reflect our own expectations about the assumptions that market participants would use in measuring the fair value of an asset or liability. For cash and cash equivalents, restricted cash, accounts receivable, prepaid expenses and other current assets, accounts payable, accrued liabilities and certain notes payable, the carrying amounts approximate fair value due to the short-term nature or maturity of the instruments. The carrying value of the Exit Facility approximates its fair value because the interest rate is variable and reflective of market rates, which are Level 2 inputs within the fair value hierarchy. Our commodity derivative instruments historically consisted of financially settled crude oil and natural gas puts, swaps, put spreads, costless collars and three way collars. We estimated the fair values of these instruments based on published forward commodity price curves, market volatility and contract terms as of the date of the estimate. The discount rate used in the discounted cash flow projections is based on published London Interbank offered rates. The fair values of commodity derivative instruments in an asset position include a measure of counterparty nonperformance risk, and the fair values of commodity derivative instruments in a liability position include a measure of our own nonperformance risk, each based on the current published issuer-weighted corporate default rates. See Note 6 – “Derivative Financial Instruments.” The fair value of our restricted stock units equals the market value of the underlying common stock on the date of grant . For our stock options, we utilize the Black-Scholes-Merton model to determine fair value, which incorporates various assumptions as follows: · the expected volatility is based on comparable companies’ asset volatilities ; · the risk-free interest rate is the related United States Treasury yield curve for periods within the expected term of the option at the time of grant; and · the dividend yield on our common stock is zero. During the three months ended March 31, 2018 we did not have any transfers from or to any level within the fair value hierarchy. The following table presents the fair value of our Level 2 financial instruments ( in thousands ): Level 2 As of March 31, As of December 31, 2018 2017 Assets: Oil and Natural Gas Derivatives $ - $ - Liabilities: Oil and Natural Gas Derivatives $ 32,354 $ 32,567 The following table sets forth the outstanding and estimated fair values of our long-term debt instruments which are classified as Level 2 financial instruments ( in thousands ): March 31, 2018 December 31, 2017 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Exit Facility $ 63,996 $ 63,996 $ 73,996 $ 73,996 $ 63,996 $ 63,996 $ 73,996 $ 73,996 |
Prepayments and Accrued Liabili
Prepayments and Accrued Liabilities | 3 Months Ended |
Mar. 31, 2018 | |
Prepayments and Accrued Liabilities | |
Prepayments and Accrued Liabilities | Note 14 — Prepayments and Accrued Liabilities Prepayments and other current assets and accrued liabilities consist of the following ( in thousands ): March 31, December 31, 2018 2017 Prepaid expenses and other current assets Advances to joint interest partners $ 830 $ 1,381 Insurance 4,761 5,949 Inventory 315 394 Royalty deposit 1,021 1,021 Other 5,220 12,857 Total prepaid expenses and other current assets $ 12,147 $ 21,602 Accrued liabilities Advances from joint interest partners - 81 Employee benefits and payroll 3,262 6,791 Interest payable 313 185 Accrued hedge payable 4,381 2,491 Undistributed oil and gas proceeds 17,229 20,079 Severance taxes payable 1,328 558 Other 14,819 15,309 Total accrued liabilities $ 41,332 $ 45,494 |
Subsequent Events
Subsequent Events | 3 Months Ended |
Mar. 31, 2018 | |
Subsequent Events | |
Subsequent Events | Note 15 — Subsequent Events In April 2018, we unwound 3,000 BPD of our WTI swaps for the period from April 1, 2018 to June 30, 2018 and replaced the unwound swaps with 3,000 BPD ICE Brent swaps with an average swap price of $61.00 per BBL for the period from January 2019 to December 2019. Additionally, we added 3,000 BPD ICE Brent costless collars with a floor price of $60.00 and a ceiling price of $82.00 for the period April 13, 2018 to June 30, 2018. |
Summary of Significant Accoun21
Summary of Significant Accounting Policies and Recent Accounting Pronouncement (Policies) | 3 Months Ended |
Mar. 31, 2018 | |
Summary of Significant Accounting Policies and Recent Accounting Pronouncements | |
Principles of Consolidation and Reporting | Principles of Consolidation and Reporting. The accompanying consolidated financial statements on March 31, 2018 include the accounts of EGC and its wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the U.S. (“U.S. GAAP”). All intercompany accounts and transactions are eliminated in consolidation. Our interests in oil and natural gas exploration and production ventures and partnerships are proportionately consolidated. The consolidated financial statements for the prior period include certain reclassifications to conform to the current presentation. Those reclassifications did not have any impact on the previously reported consolidated result of operations or cash flows. |
Use of Estimates | Use of Estimates. The preparation of consolidated financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the dates of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Estimates of proved reserves are key components of our depletion rate for our proved oil and natural gas properties and the full cost ceiling test limitation. Other items subject to estimates and assumptions include fair value estimates used in fresh start accounting; accounting for acquisitions and dispositions; carrying amounts of property, plant and equipment; asset retirement obligations; deferred income taxes; valuation of derivative financial instruments; among others. Accordingly, our accounting estimates require the exercise of judgment by management in preparing such estimates. While we believe that the estimates and assumptions used in preparation of our consolidated financial statements are appropriate, actual results could differ from those estimates, and any such differences may be material. |
Interim Financial Statements | Interim Financial Statements. The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP for interim financial information and with the instructions to Form 10‑Q and Article 10 of Regulation S-X. Accordingly, they do not include all of the information and footnotes required by U.S. GAAP for complete financial statements. In the opinion of management, all adjustments of a normal and recurring nature considered necessary for a fair presentation have been included in the accompanying consolidated financial statements. The results of operations for the interim period are not necessarily indicative of the results that will be realized for the entire fiscal year. These consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the 2017 Annual Report. |
Recent Accounting Pronouncements | Recent Accounting Pronouncements. In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014‑09, Revenue from Contracts with Customers (“ASU 2014‑09”), as a new Accounting Standards Codification (ASC) Topic, ASC 606. ASU 2014‑09 is effective for us beginning in the first quarter of 2018. In May 2016, the FASB issued ASU 2016-11, which rescinds certain SEC guidance in the related ASC, including guidance related to the use of the “entitlements” method of revenue recognition used by the Company. The Company adopted ASC 606 effective January 1, 2018, which replaces previous revenue recognition requirements under FASB ASC Topic 605 – Revenue Recognition (“ASC 605”). The standard was adopted using the modified retrospective approach which requires the Company to recognize in retained earnings at the date of adoption the cumulative effect of the application of ASC 606 to all existing revenue contracts which were not substantially complete as of January 1, 2018. T he Company has elected the contract modification practical expedient which allows the Company to reflect the aggregate effect of all modifications prior to the date of adoption when applying ASC 606. Although the adoption of ASC 606 did not have an impact on the Company’s net loss or cash flows, it did result in the reclassification of certain fees received under pipeline gathering and transportation and pipeline tariff agreements that were previously included in oil sales to other revenue i n the consolidated statements of operations. The Company has determined that its contracts for the sale of crude oil, unprocessed natural gas and NGLs contain monthly performance obligations to deliver product at locations specified in the contract. Control is transferred at the delivery location, at which point the performance obligation has been satisfied and revenue is recognized. Fees included in the contract that are incurred prior to control transfer are classified as lease operating expense and fees incurred after control transfers are included as a reduction to the transaction price. The transaction price at which revenue is recognized consists entirely of variable consideration based on quoted market prices less various fees and the quantity of volumes delivered. The Company receives payment for product sales from one to three months after delivery. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated and amounts due from customers are accrued in accounts receivable, oil and natural gas sales in the consolidated balance sheets. Variances between the Company’s estimated revenue and actual payments are recorded in the month the payment is received, however, differences have been and are insignificant. The Company has elected to utilize the practical expedient in ASC 606 that states the 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. Under our contracts, each monthly delivery of product 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. The Company previously utilized the entitlements method to account for natural gas imbalances, which is no longer applicable under ASC 606. The impact to the financial statements resulting from this change in accounting for our natural gas imbalances was not significant. In February 2016, the FASB issued ASU No. 2016‑02, Leases ( “ ASU 2016‑02”), to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. To meet that objective, the FASB amended the FASB Accounting Standards Codification and created Topic 842, Leases . The guidance in this ASU supersedes Topic 840, Leases. The new standard establishes a right-of-use (“ROU”) model that requires a lessee to record a ROU asset and a lease liability on the balance sheet for all leases with terms longer than 12 months. Leases will be classified as either finance or operating, with classification affecting the pattern of expense recognition in the income statement. The new standard is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years. In the normal course of business, we enter into lease agreements to support our operations. We are evaluating the provisions of ASU 2016‑02 to determine the quantitative effects it will have on our consolidated financial statements and related disclosures. We believe the adoption and implementation of this ASU will have a material impact on our balance sheet resulting from an increase in both assets and liabilities relating to our leasing activities. In June 2016, the FASB issued ASU No. 2016‑13, Credit Losses, Measurement of Credit Losses on Financial Instruments (“ASU 2016‑13”). ASU 2016‑13 significantly changes how entities will measure credit losses for most financial assets and certain other instruments that are not measured at fair value through net income. The standard will replace today’s incurred loss approach with an expected loss model for instruments measured at amortized cost. Entities will apply the standard’s provisions as a cumulative-effect adjustment to retained earnings as of the beginning of the first reporting period in which the guidance is effective. This ASU is effective for public entities for annual and interim periods beginning after December 15, 2019. Early adoption is permitted for all entities for annual periods beginning after December 15, 2018, and interim periods therein. We have not yet determined the effect of this standard on our consolidated financial position, results of operations or cash flows. In August 2016, the FASB issued ASU No. 2016‑15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016‑15”). ASU 2016‑15 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. Our adoption of ASU 2016‑15 on January 1, 2018 using the retrospective transition method had no effect on our consolidated financial position, results of operations or cash flows other than presentation. In November 2016, the FASB issued ASU No. 2016‑18 , Statement of Cash Flows (Topic 230): Restricted Cash (ASU 2016‑18). ASU 2016‑18 requires amounts generally described as restricted cash and restricted cash equivalents be included with cash and cash equivalents when reconciling the total beginning and ending amounts for the periods shown on the statement of cash flows. Our adoption of ASU 2016‑18 on January 1, 2018 had no effect on our consolidated financial position, results of operations or cash flows other than presentation. |
Property and Equipment (Tables)
Property and Equipment (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Property and Equipment | |
Schedule of property and equipment | Property and equipment consists of the following ( in thousands ): As of March 31, As of December 31, 2018 2017 Oil and natural gas properties - full cost method of accounting Proved properties $ 1,328,528 $ 1,307,009 Less: accumulated depreciation, depletion, amortization and impairment (764,952) (742,286) Proved properties, net 563,576 564,723 Unevaluated properties 195,907 200,199 Oil and natural gas properties, net 759,483 764,922 Other property and equipment 13,902 13,780 Less: accumulated depreciation and impairment (4,745) (3,660) Other property and equipment, net 9,157 10,120 Total property and equipment, net of accumulated depreciation, depletion, amortization and impairment $ 768,640 $ 775,042 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Long-Term Debt | |
Schedule of long-term debt | As of March 31, 2018 and December 31, 2017 our outstanding debt consisted of the following ( in thousands ): Successor March 31, 2018 December 31, 2017 Exit Facility $ 63,996 $ 73,996 Capital lease obligations 21 21 Total debt 64,017 74,017 Less: debt issue costs 39 44 Less: current maturities 5,571 21 Total long-term debt $ 58,407 $ 73,952 |
Asset Retirement Obligations (T
Asset Retirement Obligations (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Asset Retirement Obligations | |
Schedule of changes in asset retirement obligations | The following table describes the changes to our asset retirement obligations ( in thousands ): Balance as of December 31, 2017 $ 664,851 Liabilities incurred 8,722 Liabilities settled (18,804) Revisions 7,633 Accretion expense 11,118 Total balance as of March 31, 2018 673,520 Less: current portion 53,415 Long-term portion as of March 31, 2018 $ 620,105 |
Derivative Financial Instrume25
Derivative Financial Instruments (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Derivative Financial Instruments | |
Schedule of derivative positions | As of March 31, 2018, we had the following open crude oil derivative positions: Weighted Average Type of Volumes Contract Price Remaining Contract Term Contract Index (MBbls) Swaps April 2018 - December 2018 Swaps NYMEX-WTI $ 50.68 April 2018 - June 2018 Swaps Argus-LLS $ 55.45 April 2018 - June 2018 Swaps ICE Brent $ 56.59 |
Schedule of fair value of our derivative instruments | The fair values of derivative instruments in our consolidated balance sheets were as follows ( in thousands ): Asset Derivative Instruments Liability Derivative Instruments March 31, 2018 December 31, 2017 March 31, 2018 December 31, 2017 Balance Fair Value Balance Fair Value Balance Fair Value Balance Fair Value Derivative financial instruments Current $ - Current $ - Current $ 32,354 Current $ 32,567 Non- - Non- - Non- - Non- - Total gross derivative financial instruments subject to enforceable master netting agreement - - 32,354 32,567 Derivative financial instruments Current - Current - Current - Current - Non- - Non- - Non- - Non- - Gross amounts offset in Balance Sheets - - - - Net amounts presented in Balance Sheets Current - Current - Current 32,354 Current 32,567 Non- - Non- - Non- - Non- - $ - $ - $ 32,354 $ 32,567 |
Schedule of the components of the gain (loss) on derivative instruments | The following table presents information about the components of the (loss) gain on derivative financial instruments ( in thousands ). Three Months Ended Three Months Ended March 31, March 31, (Loss) gain on derivative financial instruments 2018 2017 Cash settlements $ (13,047) $ 289 Non-cash gain in fair value 213 3,409 Total (loss) gain on derivative financial instruments $ (12,834) $ 3,698 |
Supplemental Cash Flow Inform26
Supplemental Cash Flow Information (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Supplemental Cash Flow Information | |
Schedule of supplemental cash flow information | The following table presents our supplemental cash flow information ( in thousands ): Three Months Ended Three Months Ended March 31, March 31, 2018 2017 Cash paid for interest $ 3,560 $ 2,817 Cash paid for income taxes - - |
Schedule of non-cash investing and financing activities | Three Months Ended Three Months Ended March 31, March 31, 2018 2017 Cash paid for interest $ 3,560 $ 2,817 Cash paid for income taxes - - The following table presents our non-cash investing and financing activities ( in thousands ): Three Months Ended Three Months Ended March 31, March 31, 2018 2017 Changes in capital expenditures and accrued liabilities or accounts payable $ (8,076) $ (2,660) Changes in asset retirement obligations 16,355 (133,434) |
Schedule of reconciliation of cash, cash equivalents and restricted cash | The following table presents the reconciliation of cash, cash equivalents and restricted cash as presented on the consolidated statement of cash flows (in thousands) : As of March 31, December 31, March 31, 2018 2017 2017 Cash and cash equivalents $ 112,062 $ 151,729 $ 160,479 Restricted cash, current 6,409 6,392 7,114 Restricted cash, long term 25,758 25,712 25,606 Total Cash, cash equivalents and restricted cash $ 144,229 $ 183,833 $ 193,199 |
Loss per Share (Tables)
Loss per Share (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Loss per Share | |
Schedule of basic and diluted earnings (loss) per share | The following table sets forth the calculation of basic and diluted loss per share (“EPS”) ( in thousands, except per share data ): Three Months Ended Three Months Ended March 31, March 31, 2018 2017 Net loss $ (33,055) $ (64,547) Weighted average shares outstanding for basic EPS 33,296 33,228 Add dilutive securities - - Weighted average shares outstanding for diluted EPS 33,296 33,228 Loss per share Basic and Diluted $ (0.99) $ (1.94) |
Fair Value of Financial Instr28
Fair Value of Financial Instruments (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Fair Value of Financial Instruments | |
Schedule of the fair value of Level 1 and Level 2 financial instruments | The following table presents the fair value of our Level 2 financial instruments ( in thousands ): Level 2 As of March 31, As of December 31, 2018 2017 Assets: Oil and Natural Gas Derivatives $ - $ - Liabilities: Oil and Natural Gas Derivatives $ 32,354 $ 32,567 |
Schedule of details of Level 2 financial instruments | The following table sets forth the outstanding and estimated fair values of our long-term debt instruments which are classified as Level 2 financial instruments ( in thousands ): March 31, 2018 December 31, 2017 Carrying Value Estimated Fair Value Carrying Value Estimated Fair Value Exit Facility $ 63,996 $ 63,996 $ 73,996 $ 73,996 $ 63,996 $ 63,996 $ 73,996 $ 73,996 |
Prepayments and Accrued Liabi29
Prepayments and Accrued Liabilities (Tables) | 3 Months Ended |
Mar. 31, 2018 | |
Prepayments and Accrued Liabilities | |
Schedule of prepayments and accrued liabilities | Prepayments and other current assets and accrued liabilities consist of the following ( in thousands ): March 31, December 31, 2018 2017 Prepaid expenses and other current assets Advances to joint interest partners $ 830 $ 1,381 Insurance 4,761 5,949 Inventory 315 394 Royalty deposit 1,021 1,021 Other 5,220 12,857 Total prepaid expenses and other current assets $ 12,147 $ 21,602 Accrued liabilities Advances from joint interest partners - 81 Employee benefits and payroll 3,262 6,791 Interest payable 313 185 Accrued hedge payable 4,381 2,491 Undistributed oil and gas proceeds 17,229 20,079 Severance taxes payable 1,328 558 Other 14,819 15,309 Total accrued liabilities $ 41,332 $ 45,494 |
Organization (Details)
Organization (Details) | 3 Months Ended |
Mar. 31, 2018itemft | |
Oil and natural gas properties | |
Number of oil fields owned and operated | item | 9 |
Maximum | |
Oil and natural gas properties | |
Off shore oil and gas properties, Depth of water (in feet) | ft | 1,000 |
Summary of Significant Accoun31
Summary of Significant Accounting Policies and Recent Accounting Pronouncements - Revenue (Details) | 3 Months Ended |
Mar. 31, 2018 | |
Minimum | |
Revenue | |
Period over which entity receives payment for sales after delivery | 1 month |
Maximum | |
Revenue | |
Period over which entity receives payment for sales after delivery | 3 months |
Property and Equipment - Schedu
Property and Equipment - Schedule (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Oil and gas properties | ||
Proved properties | $ 1,328,528 | $ 1,307,009 |
Less: accumulated depreciation, depletion, amortization and impairment | (764,952) | (742,286) |
Proved properties, net | 563,576 | 564,723 |
Unevaluated properties | 195,907 | 200,199 |
Oil and gas properties, net | 759,483 | 764,922 |
Other property and equipment | 13,902 | 13,780 |
Less: accumulated depreciation | (4,745) | (3,660) |
Other property and equipment, net | 9,157 | 10,120 |
Total Property and Equipment, net of accumulated depreciation, depletion, amortization and impairment | $ 768,640 | $ 775,042 |
Property and Equipment - Impair
Property and Equipment - Impairment (Details) $ in Thousands | 3 Months Ended |
Mar. 31, 2017USD ($) | |
Impairment | |
Impairment of oil and natural gas properties | $ 40,774 |
Property and Equipment - Additi
Property and Equipment - Additional information (Details) $ in Millions | 3 Months Ended |
Mar. 31, 2018USD ($) | |
Property and Equipment | |
Reduction in unevaluated properties | $ 4.3 |
Amortization to evaluated properties | 2.2 |
Unevaluated properties costs transferred to evaluated properties | $ 2.1 |
Long-Term Debt - Schedule of Lo
Long-Term Debt - Schedule of Long-Term Debt (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Long-Term Debt | ||
Total debt | $ 64,017 | $ 74,017 |
Less: debt issue costs | 39 | 44 |
Less: current maturities | 5,571 | 21 |
Total long-term debt | 58,407 | 73,952 |
Exit Facility | ||
Long-Term Debt | ||
Total debt | 63,996 | 73,996 |
Capital lease obligations | ||
Long-Term Debt | ||
Total debt | $ 21 | $ 21 |
Long-Term Debt - Exit Facility
Long-Term Debt - Exit Facility (Details) $ in Thousands | Mar. 29, 2018USD ($) | Dec. 30, 2016item | Jun. 30, 2018USD ($) | Mar. 31, 2018USD ($)item | Mar. 31, 2017USD ($) | Dec. 31, 2017USD ($) |
Long-Term Debt | ||||||
Payments on long-term debt | $ 10,000 | $ 10,002 | $ 602 | |||
Debt | $ 64,017 | $ 74,017 | ||||
Exit Facility | ||||||
Long-Term Debt | ||||||
Minimum percentage of total value of the entity's and subsidiary guarantors' proved reserves required to be covered by mortgages to secure debt | 90.00% | |||||
Number of facilities | item | 2 | |||||
Minimum Current ratio | 1 | |||||
Maximum Leverage ratio | 4 | |||||
Leverage ratio, Number of trailing quarters | item | 4 | |||||
Debt | $ 63,996 | $ 73,996 | ||||
Letters of credit | $ 201,500 | |||||
Exit Term Loan | ||||||
Long-Term Debt | ||||||
Asset coverage ratio threshold to make mandatory payment on exit term loan | 1.50 | |||||
Percentage of aggregate outstanding principal amount to be prepaid if asset coverage ratio is less than threshold | 7.50% | |||||
Amount available for borrowing | $ 12,500 | |||||
Maximum available for revolving loans | $ 25,000 | |||||
Exit Term Loan | Forecast | ||||||
Long-Term Debt | ||||||
Contingent prepayment of debt during the fiscal quarter ending June 30, 2018 | $ 5,550 | |||||
Exit Revolving Facility | ||||||
Long-Term Debt | ||||||
Commitment fee (as a percent) | 0.50% | |||||
Letter of credit, rate of fees accrual (as a percent) | 4.50% | |||||
Letter of credit, rate of issuance fee per annum (as a percent) | 0.25% | |||||
Base Rate | Exit Term Loan | ||||||
Long-Term Debt | ||||||
Percentage points added to reference rate (as a percent) | 3.50% | |||||
Base Rate | Exit Revolving Facility | ||||||
Long-Term Debt | ||||||
Percentage points added to reference rate (as a percent) | 3.50% | |||||
LIBO Rate | Exit Term Loan | ||||||
Long-Term Debt | ||||||
Percentage points added to reference rate (as a percent) | 4.50% | |||||
LIBO Rate | Exit Revolving Facility | ||||||
Long-Term Debt | ||||||
Percentage points added to reference rate (as a percent) | 4.50% |
Asset Retirement Obligations (D
Asset Retirement Obligations (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2017 | |
Asset Retirement Obligations | ||
Beginning of period total | $ 664,851 | |
Liabilities incurred | 8,722 | |
Liabilities settled | (18,804) | |
Revisions | 7,633 | |
Accretion expense | 11,118 | |
End of period total | 673,520 | |
Less: current portion | 53,415 | $ 51,398 |
Long-term portion | $ 620,105 | $ 613,453 |
Derivative Financial Instrume38
Derivative Financial Instruments - Positions (Details) | 3 Months Ended |
Mar. 31, 2018$ / bblbbl | |
Swap, Remaining contract term April 2018 to December 2018, NYMEX-WTI | |
Net open crude oil derivative positions | |
Volumes (MBbls) | bbl | 2,200 |
Weighted average contract price, Swaps | $ / bbl | 50.68 |
Swap, Remaining contract term April 2018 to June 2018, Argus-LLS | |
Net open crude oil derivative positions | |
Volumes (MBbls) | bbl | 182 |
Weighted average contract price, Swaps | $ / bbl | 55.45 |
Swap, Remaining contract term April 2018 to June 2018, ICE Brent | |
Net open crude oil derivative positions | |
Volumes (MBbls) | bbl | 227.5 |
Weighted average contract price, Swaps | $ / bbl | 56.59 |
Derivative Financial Instrume39
Derivative Financial Instruments - Fair Values (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Liability Derivative Instruments | ||
Gross derivative financial instruments subject to enforceable master netting agreement | $ 32,354 | $ 32,567 |
Net amounts presented in Balance Sheets | 32,354 | 32,567 |
Current Liabilities | ||
Liability Derivative Instruments | ||
Gross derivative financial instruments subject to enforceable master netting agreement | 32,354 | 32,567 |
Net amounts presented in Balance Sheets | $ 32,354 | $ 32,567 |
Derivative Financial Instrume40
Derivative Financial Instruments - (Loss) Gain (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Derivative Financial Instruments | ||
Cash settlements | $ (13,047) | $ 289 |
Non-cash gain in fair value | 213 | 3,409 |
Total (loss) gain on derivative financial instruments | (12,834) | $ 3,698 |
Deposits for collateral with counterparties | $ 0 |
Income Taxes (Details)
Income Taxes (Details) - USD ($) $ in Millions | 3 Months Ended | 12 Months Ended | |
Mar. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2017 | |
Income Taxes | |||
Cash paid for income taxes | $ 0 | ||
Effective income tax rate (benefit) (as a percent) | 0.00% | ||
Increase in valuation allowance | $ 7 | ||
Valuation allowance | 313 | $ 306 | |
Change in deferred tax assets related to Tax Cuts and Jobs Act of 2017 | 0 | ||
Change in valuation allowance related to Tax Cuts and Jobs Act of 2017 | $ 0 | ||
Forecast | |||
Income Taxes | |||
Cash paid for income taxes | $ 0 | ||
Effective income tax rate (benefit) (as a percent) | 0.00% |
Stockholders' Equity (Details)
Stockholders' Equity (Details) - $ / shares | 3 Months Ended | ||
Mar. 31, 2018 | Dec. 31, 2017 | Dec. 30, 2016 | |
Stockholders' Equity | |||
Capital stock, shares authorized | 110,000,000 | ||
Common stock, shares authorized | 100,000,000 | 100,000,000 | 100,000,000 |
Common stock, par value | $ 0.01 | $ 0.01 | $ 0.01 |
Preferred stock, shares authorized | 10,000,000 | 10,000,000 | 10,000,000 |
Preferred stock, par value | $ 0.01 | $ 0.01 | $ 0.01 |
Common stock issued upon vesting of restricted stock units (in shares) | 13,515 | ||
Common stock, shares outstanding | 33,268,478 | 33,254,963 | |
Warrants outstanding (in shares) | 2,119,889 |
Supplemental Cash Flow Inform43
Supplemental Cash Flow Information - Supplemental (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Supplemental Cash Flow Information | ||
Cash paid for interest | $ 3,560 | $ 2,817 |
Cash paid for income taxes | $ 0 |
Supplemental Cash Flow Inform44
Supplemental Cash Flow Information - Non-cash Investing and Financing Activities (Details) - USD ($) $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Non-cash investing and financing activities | ||
Changes in capital expenditures accrued or accounts payable | $ (8,076) | $ (2,660) |
Changes in asset retirement obligations | $ 16,355 | $ (133,434) |
Supplemental Cash Flow Inform45
Supplemental Cash Flow Information - Reconciliation of cash, cash equivalents and restricted cash (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 | Mar. 31, 2017 | Dec. 31, 2016 |
Supplemental Cash Flow Information | ||||
Cash and cash equivalents | $ 112,062 | $ 151,729 | $ 160,479 | |
Restricted cash, current | 6,409 | 6,392 | 7,114 | |
Restricted cash, long term | 25,758 | 25,712 | 25,606 | |
Total Cash, cash equivalents and restricted cash | $ 144,229 | $ 183,833 | $ 193,199 | $ 223,288 |
Employee Benefit Plans - 2016 P
Employee Benefit Plans - 2016 Plan (Details) - 2016 Long Term Incentive Plan - shares | Apr. 29, 2017 | Dec. 30, 2016 |
Employee Benefit Plans | ||
Number of shares reserved | 1,859,552 | |
Percentage of equity reserved under plan | 5.00% | |
Percentage of total new equity that must be allocated | 3.00% | |
Maximum period in which percentage of total new equity must be allocated | 120 days | |
Percentage of total new equity allocated | 3.00% |
Employee Benefit Plans - Stock
Employee Benefit Plans - Stock options (Details) - Stock Options - 2016 Long Term Incentive Plan | 3 Months Ended |
Mar. 31, 2018 | |
Employee Benefit Plans | |
Share-based award, expiration period | 10 years |
Share-based award, vesting period | 3 years |
Employee Benefit Plans - Stoc48
Employee Benefit Plans - Stock option valuation assumptions (Details) - Stock Options - 2016 Long Term Incentive Plan $ in Millions | Mar. 31, 2018USD ($)shares |
Employee Benefit Plans | |
Unvested stock options (in shares) | shares | 285,105 |
Unrecognized compensation expense (in dollars) | $ | $ 1.2 |
Employee Benefit Plans - Restri
Employee Benefit Plans - Restricted stock units (Details) - Restricted Stock Units - 2016 Long Term Incentive Plan $ / shares in Units, $ in Millions | 3 Months Ended |
Mar. 31, 2018USD ($)$ / sharesshares | |
Employee Benefit Plans | |
Share-based award, vesting period | 3 years |
Number of shares for which each unit provides right to receive | 1 |
Restricted Stock Units | |
Granted (in shares) | 796,967 |
Outstanding at end of period (in shares) | 1,316,579 |
Weighted average share price (in dollars per share) | $ / shares | $ 6.12 |
Unrecognized compensation expense | $ | $ 10.1 |
Employee Benefit Plans - 2018 P
Employee Benefit Plans - 2018 Plan (Details) - shares | 12 Months Ended | ||
Dec. 31, 2018 | Apr. 11, 2018 | Dec. 30, 2016 | |
2016 Long Term Incentive Plan | |||
Employee Benefit Plans | |||
Number of shares reserved | 1,859,552 | ||
Number of shares available for award | 37,835 | ||
2018 Long Term Incentive Plan | Forecast | |||
Employee Benefit Plans | |||
Number of shares approved for grant | 1,860,000 |
Loss per Share - EPS (Details)
Loss per Share - EPS (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Loss per Share | ||
Net loss | $ (33,055) | $ (64,547) |
Weighted average shares outstanding for basic EPS | 33,296 | 33,228 |
Weighted average shares outstanding for diluted EPS | 33,296 | 33,228 |
Loss per share, Basic and Diluted (in dollars per share) | $ (0.99) | $ (1.94) |
Loss per Share - Other (Details
Loss per Share - Other (Details) - USD ($) $ in Millions | 3 Months Ended | |
Mar. 31, 2018 | Mar. 31, 2017 | |
Other disclosures | ||
Loss allocated to participating securities (in dollars) | $ 0 | $ 0 |
Anti-dilutive securities (in shares) | 3,665,257 | 1,206,765 |
Commitments and Contingencies -
Commitments and Contingencies - Letters of Credit and Performance Bonds (Details) $ in Millions | Mar. 31, 2018USD ($) |
Letters of Credit and Performance Bonds | |
Performance bonds outstanding | $ 325.8 |
Cash collateral | 47.9 |
Exit Facility | |
Letters of Credit and Performance Bonds | |
Letters of credit | 201.5 |
Exit Facility | ExxonMobil | |
Letters of Credit and Performance Bonds | |
Letters of credit | 200 |
Performance Bond, Lease and area bonds | |
Letters of Credit and Performance Bonds | |
Performance bonds outstanding | 174.1 |
Performance Bonds, Wells and facilities | |
Letters of Credit and Performance Bonds | |
Performance bonds outstanding | $ 151.7 |
Commitments and Contingencies54
Commitments and Contingencies - Drilling Rig Commitments (Details) - Drilling Rig Contracts $ in Millions | 3 Months Ended |
Mar. 31, 2018USD ($)contract | |
Drilling Rig Commitments | |
Drilling rig commitments | $ | $ 10.7 |
Number of contracts | contract | 2 |
Commitments and Contingencies55
Commitments and Contingencies - Other (Details) $ in Millions | Mar. 31, 2018USD ($) |
Bonding requirements | |
Other | |
Restricted cash | $ 25.7 |
Future plugging, abandonment and other decommissioning costs | |
Other | |
Restricted cash | $ 6.1 |
Fair Value of Financial Instr56
Fair Value of Financial Instruments - Dividend Yield (Details) | 3 Months Ended |
Mar. 31, 2018 | |
Black-Scholes option pricing model assumptions: | |
Dividend yield (as a percent) | 0.00% |
Fair Value of Financial Instr57
Fair Value of Financial Instruments - Assets and Liabilities (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Liabilities: | ||
Oil and Natural Gas Derivatives, Liabilities | $ 32,354 | $ 32,567 |
Level 2 | ||
Liabilities: | ||
Oil and Natural Gas Derivatives, Liabilities | $ 32,354 | $ 32,567 |
Fair Value of Financial Instr58
Fair Value of Financial Instruments - Long-term debt instruments (Details) - Level 2 - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Carrying Value | ||
Long-Term Debt | ||
Long-term debt instruments | $ 63,996 | $ 73,996 |
Estimated of Fair Value | ||
Long-Term Debt | ||
Long-term debt instruments | 63,996 | 73,996 |
Exit Facility | Carrying Value | ||
Long-Term Debt | ||
Long-term debt instruments | 63,996 | 73,996 |
Exit Facility | Estimated of Fair Value | ||
Long-Term Debt | ||
Long-term debt instruments | $ 63,996 | $ 73,996 |
Prepayments and Accrued Liabi59
Prepayments and Accrued Liabilities (Details) - USD ($) $ in Thousands | Mar. 31, 2018 | Dec. 31, 2017 |
Prepaid expenses and other current assets | ||
Advances to joint interest partners | $ 830 | $ 1,381 |
Insurance | 4,761 | 5,949 |
Inventory | 315 | 394 |
Royalty deposit | 1,021 | 1,021 |
Other | 5,220 | 12,857 |
Total prepaid expenses and other current assets | 12,147 | 21,602 |
Accrued liabilities | ||
Advances from joint interest partners | 81 | |
Employee benefits and payroll | 3,262 | 6,791 |
Interest payable | 313 | 185 |
Accrued hedge payable | 4,381 | 2,491 |
Undistributed oil and gas proceeds | 17,229 | 20,079 |
Severance taxes payable | 1,328 | 558 |
Other | 14,819 | 15,309 |
Total accrued liabilities | $ 41,332 | $ 45,494 |
Subsequent Events (Details)
Subsequent Events (Details) - Subsequent Event | 1 Months Ended |
Apr. 30, 2018item$ / bbl | |
Swap, Remaining contract term April 2018 to June 2018, NYMEX-WTI | |
Subsequent Events | |
Unwound (BPDs) | item | 3,000 |
Swap, Contract term January 2019 to December 2019, Ice Brent | |
Subsequent Events | |
Added (BPDs) | item | 3,000 |
Weighted average contract price, Swaps | $ / bbl | 61 |
Swap, Remaining contract term April 2018 to June 2018, ICE Brent, Added April 2018 | |
Subsequent Events | |
Added (BPDs) | item | 3,000 |
Average floor price | $ / bbl | 60 |
Average ceiling price | $ / bbl | 82 |