Document and Entity Information
Document and Entity Information - USD ($) | 12 Months Ended | ||
Dec. 31, 2019 | Apr. 24, 2020 | Jun. 30, 2019 | |
Document and Entity Information | |||
Document Type | 10-K | ||
Document Period End Date | Dec. 31, 2019 | ||
Entity Registrant Name | Sundance Energy Inc. | ||
Entity Well-known Seasoned Issuer | No | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Accelerated Filer | ||
Entity Small Business | true | ||
Entity Emerging Growth Company | true | ||
Entity Ex Transition Period | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 131,992,965 | ||
Entity Common Stock, Shares Outstanding | 6,875,672 | ||
Entity Central Index Key | 0001326089 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2019 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false |
CONSOLIDATED BALANCE SHEETS
CONSOLIDATED BALANCE SHEETS - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Current assets: | ||
Cash and cash equivalents | $ 12,382 | $ 1,581 |
Accounts receivable trade and other | 27,020 | 21,249 |
Derivative financial instruments | 1,215 | 24,315 |
Income tax receivable | 3,555 | 2,384 |
Other current assets | 3,616 | 3,547 |
Assets held for sale | 23,471 | |
Total current assets | 47,788 | 76,547 |
Oil and gas properties, successful efforts method | 1,122,908 | 986,548 |
Less: accumulated depletion, depreciation and amortization | (379,961) | (293,598) |
Total oil and gas properties, net | 742,947 | 692,950 |
Other long-term assets: | ||
Other property and equipment, net of accumulated depreciation of $3,419 and $2,823 | 1,963 | 1,354 |
Income tax receivable | 1,172 | 2,344 |
Operating lease right-of-use assets | 17,331 | |
Derivative financial instruments | 878 | 8,003 |
Other long-term assets | 1,835 | 2,150 |
TOTAL ASSETS | 813,914 | 783,348 |
Current liabilities: | ||
Accounts payable trade | 43,284 | 45,137 |
Accrued liabilities | 26,409 | 25,285 |
Derivative liabilities | 4,394 | 436 |
Operating lease liabilities - current | 7,720 | |
Liabilities related to assets held for sale | 193 | |
Total current liabilities | 81,807 | 71,051 |
Long-term liabilities: | ||
Long-term debt | 353,490 | 300,804 |
Asset retirement obligations | 3,653 | 3,296 |
Operating lease liabilities - long term | 9,611 | |
Derivative financial instruments | 3,669 | 2,578 |
Deferred tax liabilities | 7,138 | 11,656 |
Other long-term liabilities | 1,149 | 1,474 |
Total long-term liabilities | 378,710 | 319,808 |
Total liabilities | 460,517 | 390,859 |
Commitments and contingencies (Note 14) | ||
Stockholders' Equity: | ||
Common stock, $0.001 value, 100,000,000 shares authorized; 6,875,672 issued and outstanding at December 31, 2019 and 6,874,622 shares issued and outstanding at December 31, 2018 | 7 | 7 |
Additional paid-in capital | 633,246 | 632,742 |
Accumulated deficit | (279,144) | (239,554) |
Accumulated other comprehensive loss | (712) | (706) |
Total stockholders' equity | 353,397 | 392,489 |
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY | $ 813,914 | $ 783,348 |
CONSOLIDATED BALANCE SHEETS (Pa
CONSOLIDATED BALANCE SHEETS (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
CONSOLIDATED BALANCE SHEETS | ||
Accumulated depreciation, other property and equipment | $ 3,419 | $ 2,823 |
Common stock, par value (in dollars per share) | $ 0.001 | $ 0.001 |
Common stock, authorized shares | 100,000,000 | 100,000,000 |
Common stock, shares issued | 6,875,672 | 6,874,622 |
Common stock, shares outstanding | 6,875,672 | 6,874,622 |
CONSOLIDATED STATEMENTS OF OPER
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Revenues: | ||
Total revenues | $ 203,580 | $ 164,933 |
Operating expenses: | ||
Lease operating and workover expense | 33,681 | 33,957 |
Gathering, processing and transportation expense | 17,086 | 8,633 |
Production taxes | 11,484 | 9,270 |
Exploration expense | 337 | 3,339 |
Depreciation, depletion and amortization expense | 92,334 | 62,814 |
Impairment expense | 9,990 | 43,828 |
General and administrative expense | 22,276 | 30,539 |
Loss (gain) on commodity derivative financial instruments | (20,542) | 40,216 |
Other expense (income), net | 1,900 | (48) |
Total operating expenses | 209,630 | 152,116 |
Income (loss) from operations: | (6,050) | 12,817 |
Other income (expense) | ||
Interest expense | (38,058) | (28,631) |
Gain on foreign currency derivative financial instruments | 6,838 | |
Total other expense | (38,058) | (21,793) |
Loss before income taxes | (44,108) | (8,976) |
Income taxes | ||
Current expense | (2,301) | |
Deferred benefit (expense) | 4,518 | (11,656) |
Total income tax benefit (expense) | 4,518 | (13,957) |
Net loss | $ (39,590) | $ (22,933) |
Loss per common share | ||
Basic and diluted | $ (5.76) | $ (4.38) |
Weighted average shares outstanding | ||
Basic and diluted | 6,874,170 | 5,236,524 |
Comprehensive loss | ||
Net loss | $ (39,590) | $ (22,933) |
Other comprehensive income (loss): | ||
Foreign currency translation | (6) | 428 |
Total comprehensive loss | (39,596) | (22,505) |
Oil sales | ||
Revenues: | ||
Total revenues | 177,853 | 140,240 |
Natural gas sales | ||
Revenues: | ||
Total revenues | 12,553 | 12,025 |
Natural gas liquid sales | ||
Revenues: | ||
Total revenues | $ 13,174 | $ 12,668 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Thousands | Common stock | Additional Paid-In Capital | Accumulated Deficit | Accumulated other comprehensive loss | Total |
Balance at the beginning of period at Dec. 31, 2017 | $ 1 | $ 389,013 | $ (216,621) | $ (1,134) | $ 171,259 |
Balance at the beginning of period (in shares) at Dec. 31, 2017 | 1,253,250 | ||||
Fractional shares issued upon reverse split (in shares) | 10 | ||||
Shares issued in connection with private placement | $ 6 | 253,511 | $ 253,517 | ||
Shares issued in connection with private placement (in shares) | 5,614,446 | 5,614,446 | |||
Private placement offering costs, net of tax | (10,297) | $ (10,297) | |||
Stock-based compensation | 515 | 515 | |||
Stock-based compensation (in shares) | 6,916 | ||||
Net loss | (22,933) | (22,933) | |||
Foreign currency translation | 428 | 428 | |||
Balance at the end of period at Dec. 31, 2018 | $ 7 | 632,742 | (239,554) | (706) | 392,489 |
Balance at the end of period (in shares) at Dec. 31, 2018 | 6,874,622 | ||||
Stock-based compensation | 504 | 504 | |||
Stock-based compensation (in shares) | 1,050 | ||||
Net loss | (39,590) | (39,590) | |||
Foreign currency translation | (6) | (6) | |||
Balance at the end of period at Dec. 31, 2019 | $ 7 | $ 633,246 | $ (279,144) | $ (712) | $ 353,397 |
Balance at the end of period (in shares) at Dec. 31, 2019 | 6,875,672 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
CASH FLOWS FROM OPERATING ACTIVITIES | ||
Net loss | $ (39,590) | $ (22,933) |
Adjustments to reconcile net loss to net cash provided by operating activities: | ||
Depreciation, depletion and amortization expense | 92,334 | 62,814 |
Impairment expense | 9,990 | 43,828 |
Loss on abandonment of unproved oil and gas properties | 550 | |
Stock-based compensation | 504 | 515 |
Deferred income tax (benefit) expense | (4,518) | 11,656 |
Gain on foreign currency derivative financial instruments | (6,838) | |
Loss (gain) on commodity derivative financial instruments | 20,542 | (40,216) |
Net cash settlements received on commodity derivative contracts | 11,258 | (599) |
Premiums (paid) received on commodity derivative contracts | (152) | 634 |
Unrealized loss on interest rate swaps | 3,625 | 2,137 |
Amortization of deferred financing fees | 3,234 | 2,281 |
Write-off of deferred financing fees | 251 | |
Other | (83) | |
Changes in assets and liabilities: | ||
Accounts receivable trade and other | 2,539 | (17,728) |
Accounts payable trade | 2,512 | 9,014 |
Accrued liabilities | 9,803 | (1,144) |
Other assets and liabilities, net | (769) | (408) |
Net cash provided by operating activities | 111,229 | 43,814 |
CASH FLOWS FROM INVESTING ACTIVITIES | ||
Capital expenditures for proved oil and gas properties | (166,646) | (168,956) |
Capital expenditures for unproved oil and gas properties | (319) | (1,790) |
Acquisition of oil and gas properties | (215,790) | |
Proceeds from the sale of oil and gas properties | 17,383 | 100 |
Other property and equipment | (407) | (352) |
Net cash used in investing activities | (149,989) | (386,788) |
CASH FLOWS FROM FINANCING ACTIVITIES | ||
Proceeds from borrowings | 50,000 | 315,000 |
Repayments of borrowings | (210,194) | |
Payments of debt issuance costs | (232) | (16,040) |
Proceeds from issuance of common shares | 253,517 | |
Equity offering costs | (10,293) | |
Receipts from foreign currency derivatives | 6,838 | |
Principal payments on finance lease obligations | (187) | (11) |
Net cash provided by financing activities | 49,581 | 338,817 |
Net change in cash and cash equivalents | 10,821 | (4,157) |
CASH AND CASH EQUIVALENTS | ||
Beginning of year | 1,581 | 5,761 |
Effect of exchange rates on cash | (20) | (23) |
End of year | 12,382 | 1,581 |
SUPPLEMENTAL CASH FLOW DISCLOSURES | ||
Income taxes paid | 2,301 | |
Interest paid, net of amounts capitalized | 26,203 | 26,359 |
NON-CASH INVESTING AND FINANCING ACTIVITIES | ||
Accounts payable and accrued expenses for oil and gas properties | $ 25,000 | $ 38,508 |
BASIS OF PRESENTATION AND SUMMA
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2019 | |
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | NOTE 1 – BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Description of Operations On November 26, 2019, a new Delaware corporation named Sundance Energy Inc. (the “Company”) acquired all of the issued and outstanding ordinary shares of Sundance Energy Australia Limited (“SEAL”), an Australian Company, pursuant to a Scheme of Arrangement under Australian law (the “Scheme”) which was approved by SEAL’s shareholders on November 8, 2019 and the Federal Court of Australia on November 14, 2019. These events are collectively referred to as the “Redomiciliation”. Prior to the Redomiciliation, the Company’s ordinary shares were listed on the Australian Securities Exchange (“ASX”) and Sundance Energy Inc. had no business or operations. Following the Redomiciliation, the business and the operations of In the Redomiciliation, all outstanding SEAL ordinary shares on November 26, 2019, were cancelled and shares of the Company’s common stock, par value $0.001 per share, were issued. Each of SEAL’s shareholders received one share of the Company’s common stock in exchange for 100 SEAL ordinary shares held. The purpose of the Redomiciliation was to reorganize the operations of SEAL, a public company incorporated under the laws of the State of South Australia, into a structure whereby the ultimate parent company of the Sundance group of companies would be a Delaware corporation. In connection with the Redomiciliation, the ordinary shares of SEAL were delisted from the ASX, and the common stock of Sundance Energy Inc. began trading on the Nasdaq Global Market on November 26, 2019 under the ticker symbol “SNDE”, the same symbol under which SEAL’s American Depository Shares were traded on Nasdaq Global Market prior to the implementation of the Redomiciliation. Immediately following the effectiveness of the Redomiciliation, SEAL distributed all of its assets to Sundance Energy Inc., and Sundance Energy Inc. assumed all of the liabilities of SEAL. Sundance Energy Inc. is an independent oil and gas company engaged in the development, production and exploration of oil, natural gas and natural gas liquids (“NGLs”) primarily targeting the Eagle Ford basin in South Texas. Basis of Preparation Prior to the Redomiciliation, SEAL reported its consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”). Following the Redomiciliation, the Company retroactively transitioned to accounting principles generally accepted in the United States of America (“GAAP”) and applied GAAP retrospectively for all prior periods presented. The Company’s consolidated financial statements have been prepared in accordance with GAAP and Securities and Exchange Commission (“SEC”) rules and regulations, and include the accounts of the Company and its consolidated subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. Going Concern The accompanying consolidated financial statements are prepared in accordance with GAAP applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. In March 2020, the prevailing market price for oil prices decreased from an average of approximately $60 per barrel for December 2019 to less than $20 per barrel. As described in Note 7, the Company is required to meet certain financial and non-financial covenants as a condition to its credit facilities. Under the Company’s second lien term loan (“Term Loan”), the Company is required to maintain an Asset Coverage Ratio of not less than 1.5 to 1.0, which is calculated as the value of its Total Proved Reserves (PV 9%) based upon the forward month prices quoted on the NYMEX, adjusted for basis differentials or premiums and transportation costs and to reflect the Company’s commodity hedging agreements then in effect to Total Debt. The value of the Company’s oil and gas reserves, (including “Total Proved Reserves” as described in the Term Loan agreement) is highly sensitive to future commodity prices. The Company regularly enters into commodity derivative contracts to protect the cash flows associated with the Company’s proved developed producing wells and to provide supplemental liquidity to mitigate decreases in revenue due to reductions in commodity prices. Based on the Company’s historical experience, in periods of sustained low commodity prices, the prevailing market price for oil and gas services has also decreased, including the types of costs included in the Company’s lease operating expenses, drilling costs, completion costs and costs to equip its wells. Subsequent to December 31, 2019, the Company renegotiated pricing with a number of its vendors and entered into contractual arrangements with drilling and completion service providers at reduced costs relative to the assumed costs in the Company’s year-end reserve report. Additionally, the Company has changed its field operating procedures in response to the material drop in oil prices which further reduces its cost structure relative to that assumed in the Company’s year-end reserve report. The Company continues to work to secure additional costs reductions. Commodity hedging that the Company currently has in place, combined with cost reductions are expected to reduce the impact of recent commodity price declines. However, given the recent decline and continued volatility of commodity prices, the Company cannot assert that it is probable that it will comply with the Asset Coverage Ratio and other covenants within the next 12 months following the date of this report. A breach of any covenant in Company’s credit agreements will result in default under both the Company’s Term Loan and cross default on the Company’s revolving credit facility, after any applicable grace period, which could result in acceleration of the amounts outstanding under the credit facilities by the Company’s lenders. Additionally, the Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception. The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the senior secured revolving credit facility (“Revolving Facility”) and Term Loan. The Company obtained waivers from its Revolving Facility and Term Loan lenders, executed on May 8, 2020 and May 11, 2020, respectively, to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and other related defaults Although the Company has obtained these waivers, there is no guarantee that its lenders will agree to waive events of default or potential events of default in the future. In the event that some or all of the amounts outstanding under its credit facilities are accelerated and become immediately due and payable, the Company does not have sufficient liquidity to repay such outstanding amounts. These conditions and events raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. Management is currently pursuing and evaluating several plans to mitigate the conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern, which include the following: · Renegotiating pricing with a number of its operating expenditure vendors and has realized lower drilling and completion costs on recent development relative to the costs incurred in 2019 and the assumed costs in the Company’s year-end reserve report. · Negotiating with its lenders to obtain waivers for potential failures in covenants. · Pursuing further changes to its cost structure in response to the material drop in oil prices. · Pursuing additional costs savings with its vendors and other internal costs, including a reduction in force, which occurred in early May 2020. There can be no assurance that sufficient liquidity can be obtained to meet the outstanding obligations of the Company, if repayment of its credit facilities is accelerated. As a result, and given the recent declines and continued volatility in commodity prices, the Company has concluded that management’s plans do not alleviate substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (i) oil and natural gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with business combinations; (vi) income taxes; (vii) accrued liabilities; (viii) valuation of derivative instruments; and (ix) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant negative impact to the Company’s business, financial condition, results of operations and cash flows. Cash and Cash Equivalents Cash and cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less. Accounts Receivable Trade and Other The Company has letters of credit in place with certain of its purchasers, which the Company could draw upon in the event the purchaser defaults. Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At December 31, 2019 and 2018, the Company had no allowance for doubtful accounts. At December 31, 2019 and 2018 the accounts receivable trade and other included the following (in thousands): December 31, 2019 2018 Oil, natural gas and NGL sales $ 18,211 $ 16,408 Joint interest owners 260 584 Commodity hedge contract receivables and other 4,342 4,257 Receivable due from buyer (Dimmit County oil and gas properties) 4,207 — Total accounts receivable trade and other $ 27,020 $ 21,249 Concentration of Credit Risk The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review. As of December 31, 2019, the Company had a receivable from one purchaser, a large midstream company and production purchaser, of $13.2 million that accounted for 73% of total accounts receivable for oil, natural gas and NGL sales. As of December 31, 2019, the Company has a long-term contract in place with this customer, under which the Company is subject to minimum revenue commitments for gathering, processing, transportation and marketing services totaling $54.3 million through 2022. As of December 31, 2018, the Company had a receivable due from the same customer of $12.1 million that accounted for 74% of total accounts receivable for oil, natural gas and NGL sales. The following tables present the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2019 and 2018: Year Ended December 31, 2019 Purchaser A Purchaser B Year Ended December 31, 2018 Purchaser A Purchaser B Purchaser C The Company owns nearly 100% of the working interest in the majority of the wells that it operates; therefore, joint interest billing receivables, and the related credit risk, is minimal. Further, if payment is not made by a working interest partner, the Company can withhold future payments of revenue to that working interest partner. Oil and Gas Properties Proved. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a unit-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. For the years ended December 31, 2019 and 2018, the Company recorded depletion, depreciation and amortization expense related to proved oil and gas properties of $91.4 million and $62.1 million, respectively. The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows of the assets to the assets’ net book value. If the net book value exceeds future net cash flows, then the cost of the property is written down to fair value. Fair value for oil and gas properties is generally determined based on discounted future net cash flows. There was no impairment expense during the years ended December 31, 2019 or 2018. Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized in results of operations. For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Interest is capitalized until the asset is ready for service. Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves. Capitalized costs of unproved property are transferred to proved property when related proved reserves are determined and depleted on a unit-of-production basis. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. There was no unproved property impairment expense during the years ended December 31, 2019 and 2018. Exploratory. Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage, are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining developmental well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. Costs incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (i) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed. Other Property and Equipment Other property and equipment consists of office furniture, computer equipment, software and vehicles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 3 to 20 years. Leasehold improvements are depreciated over the shorter of the lease term or the estimated useful life of the improvement. Costs that do not extend the useful lives of property and equipment are charged to expense as incurred. Major replacements, renewals and betterments are capitalized. Other Current Assets Other current assets consist of oil and equipment inventory and prepaid expenses. The Company records oil and equipment inventory at the lower of cost or net realizable value. Prepaid expenses are recorded at cost. Assets Held for Sale Oil and gas properties expected to be sold or otherwise disposed of within one year are classified as assets held for sale and included as current assets in the consolidated balance sheets are separately presented in the accompanying consolidated balance sheets at the lower of carrying value or fair value less estimated costs to sell (“FVLCS”). The Company continued to extract oil and gas from the assets while held for sale, although in accordance with accounting standards, it did not record DD&A for assets classified as held for sale. Debt Issuance Costs Debt issuance costs related to the Company’s Term Loan are included as a deduction from the carrying amount of the credit facility in the consolidated balance sheets and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the Revolving Facility are included in other long-term assets and are amortized to interest expense on a straight-line basis over the term of the facility. Derivative Instruments The Company enters into derivative contracts, primarily swaps, and costless collars, to manage its exposure to commodity price risk, and follows Financial Accounting Standards Board (“FASB”) ASC Topic 815, Derivatives and Hedging, to account for its derivative financial instruments. The Company also has interest rate swaps contracts to mitigate its exposure to the floating interest rate charged on its long-term debt. In addition, the Company historically entered into foreign exchange derivatives to protect cash flows generated during a common stock equity raise in 2018 from changes in currency fluctuations. Prior to the Company’s redomiciliation, the majority of its common stock issuances were denominated in Australian dollars. All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses from changes in the fair value of derivative instruments are recognized immediately in operations. The Company does not apply hedge accounting to any of its outstanding derivative instruments and, as a result, changes in derivative fair values are recognized as an unrealized gain or loss in operations. Cash flows from derivatives used to manage commodity price risk and interest rate risk are classified in operating activities along with the cash flows of the underlying hedged transactions. Cash flows from derivatives used to manage foreign currency risk are classified in financing activities. The Company does not enter into derivative instruments for speculative or trading purposes. Refer to the Note 10 and Note 11 for further information. Asset Retirement and Environmental Obligations Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition as specified by the lease or regulatory agencies. The Company follows FASB ASC Topic 410, Asset Retirement and Environmental Obligations , to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is spud or acquired), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a unit-of-production basis over the proved developed reserves of the related asset. Revisions typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells, and such revisions result in adjustments to the related capitalized asset and corresponding liability. Revenue Recognition The Company recognizes revenue from the sale of oil, natural gas and NGLs in the period that the performance obligations are satisfied. The Company’s performance obligations are primarily comprised of the delivery of oil, natural gas or NGLs at a delivery point. Each barrel of oil, MMBtu of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer through delivery of oil, natural gas and NGLs, which differs depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of gathering, processing, transportation, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations, and requires significant judgements. Fees and other deductions incurred prior to control transfer are recorded within the gathering, processing and transportation expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGLs production revenue. The Company has three types of contracts under which oil, gas, and NGLs production revenue is generated, which are summarized below: 1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead. 2) The Company sells unprocessed natural gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw natural gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue natural gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed natural gas under these arrangements are reflected as natural gas or NGL revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred. 3) The Company has certain processing arrangements that include the delivery of unprocessed natural gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs, control is deemed to have transferred after it has been separated from the residue gas. The midstream processor remits payment to the Company based on the proceeds it generates from selling the NGLs to other third parties. The Company recognizes the proceeds as NGL revenue. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. The Company recognizes proceeds from the downstream contracts as natural gas revenue. Under these processing arrangements for both NGL and natural gas, the Company recognizes gathering, transportation, and processing fees incurred prior to control transfer as expense recorded within the gathering, processing and transportation expense line item on the accompanying consolidated statements of operations. Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received within two months after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, metered sales volumes, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded in the month payment is received, but have not historically been material. Estimated revenue due to the Company is recorded within accounts receivable trade and other on the accompanying consolidated balance sheets until payment is received. The accounts receivable balance from contracts with customers within the accompanying balance sheet as of December 31, 2019 and 2018 was $18.2 million and $16.4 million, respectively. Stock-Based Compensation Equity - Settled Compensation Prior to the effectiveness of the Redomiciliation, SEAL issued restricted share units (“RSUs”) pursuant to its Long Term Incentive Plan (the “Plan”) to motivate management and employees to make decisions benefiting long-term value creation, retain management and employees and reward the achievement of the Company’s long-term goals. The RSUs are generally settled based on the achievement of certain goals established by the Compensation Committee and approved by the Board. There were three types of RSU awards: 1) Time based vesting: The fair value of time-based RSUs is determined based on the price of the underlying equity on the date of grant and the expense is recognized over the vesting period. 2) Total shareholder return (“TSR”) or absolute total share-holder return (“ATSR”): Certain RSUs vest based on the achievement of metrics related to the a three‑year ATSR or TSR as compared to a peer group or a market index. A Monte Carlo simulation model to determine the fair value of such RSUs and the expense is recognized over the vesting period. The Monte Carlo model was used to determine based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected volatility used in the model is based on the historical volatility commensurate with the length of the performance period of the award. The risk-free rate used in the model is based on published interest rates relevant to the term of the RSU award. 3) Performance targets: Certain RSUs vest based on the achievement of Adjusted EBITDAX per debt adjusted share or average daily production volume per debt adjusted share metrics during 2019 and 2020. At the end of each reporting period, the amount of expense recorded is adjusted based on the number of shares it ultimately expects to vest based on the comparison of internal forecasts to the performance conditions. The fair value of the equity to which employees become entitled is measured at grant date and recognized as an expense over the vesting period with a corresponding increase in equity. The Company accounts for forfeitures of RSUs as they occur. See Note 13 for further discussion of the RSUs. Defined Contribution Plan The Company has a defined contribution retirement plan for all employees. The plan is funded by employee contributions and discretionary Company contributions. The Company’s contributions for the years ended December 31, 2019 and 2018 were $0.6 million and $0.3 million, respectively. Income Taxes Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s consolidated financial statements. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense (benefit). Earnings (Loss) Per Share Basic earnings (loss) per common share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during each period. Diluted earnings per common share is calculated by dividing net income by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of outstanding restricted share units which have been issued to employees, all using the treasury stock method. When a loss from continuing operations exists, all dilutive securities and potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. Industry Segment and Geographic Information The Company’s strategic focus is the exploration, development and production of large, repeatable onshore resource plays in North America. All of the Company’s operations and assets are located in the Eagle Ford area of south Texas. Management has determined, based upon the reports the Chief Operating Decision Maker (the Company’s Chief Executive Officer) reviews and uses to make strategic decisions, that the Company has one reportable segment being oil and natural gas development and production in North America. Foreign Currency Transaction Gains and Losses The U.S. dollar is the functional currency for the Company. The Company’s Australian subsidiaries have an Australian dollar functional currency, and asset and liability accounts denominated in foreign currencies are remeasured to their U.S. dollar equivalent at the exchange rate in effect at the end of each reporting period. Foreign currency gains and losses arising from translation are reflected in accumulated other comprehensive (loss) in the consolidated balance sheets. Business Combinations A business combination is a transaction in which an acquirer obtains control of one or more businesses. The Company accounts for business combinations using the acquisition method of accounting, under which the cost of the acquisition is allocated to assets acquired and liabilities assumed based upon their respective fair values as of the acquisition date. Costs directly attributable to the business combination are expensed as incurred, except those directly and incrementally attributable to equity issuance. Recently Issued and Adopted Accounting Standards In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU 2016-02”). The FASB subsequently issued various |
OIL AND GAS PROPERTIES
OIL AND GAS PROPERTIES | 12 Months Ended |
Dec. 31, 2019 | |
OIL AND GAS PROPERTIES. | |
OIL AND GAS PROPERTIES | NOTE 2 — OIL AND GAS PROPERTIES Net capitalized costs related to the Company’s oil and gas producing activities at December 31, 2019 and 2018 are as follows (in thousands): December 31, 2019 2018 Oil and gas properties, successful efforts method: Unproved $ 25,037 $ 48,049 Proved 1,090,774 925,551 Work in progress 7,097 12,948 1,122,908 986,548 Accumulated depletion, depreciation and amortization (379,961) (293,598) Oil and gas properties, net $ 742,947 $ 692,950 Capitalized Interest For the years ended December 31, 2019 and 2018, the Company capitalized interest of $2.3 million and $1.5 million, respectively. |
ACQUISITIONS AND DISPOSITIONS
ACQUISITIONS AND DISPOSITIONS | 12 Months Ended |
Dec. 31, 2019 | |
ACQUISITIONS AND DISPOSITIONS | |
ACQUISITIONS AND DISPOSITIONS | NOTE 3 — ACQUISITIONS AND DISPOSITIONS 2019 The Company did not have any acquisitions during the year ended December 31, 2019. On October 1, 2019, the Company closed on the sale of its assets located in Dimmit County, Texas, for $21.5 million, of which $4.2 million was a receivable due to Sundance as of December 31, 2019. The disposed assets included 19 gross producing wells located on approximately 6,100 net acres. Production from these wells approximated 1,200 Boe/d during 2019 prior to the disposition. This disposal group was classified as held for sale prior to its sale. See Note 4 for further discussion. 2018 On April 23, 2018, Sundance Energy Inc. acquired from Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC (collectively the “Sellers”) approximately 21,900 net acres targeting the Eagle Ford Formation in McMullen, Live Oak, Atascosa and La Salle counties, Texas, for cash of $215.8 million, after the effective date to closing date adjustments of $5.8 million. The acquisition included working interests in 132 gross producing wells, and furthered the Company’s strategy of aggregating assets in the Eagle Ford. The following table reflects the fair value of the assets acquired and the liabilities assumed (in thousands): Assets Acquired: December 31, 2018 Oil and gas properties Proved $ 173,750 Unproved 43,642 Liabilities Assumed: Trade and other payables (80) Asset retirement obligation (1,522) Net assets acquired $ 215,790 For the period from April 23, 2018 through December 31, 2018 the acquired properties generated the following revenues and direct operating expenses, including depletion, depreciation and amortization expense: Revenues $ 64,507 Direct operating expenses (1) (45,194) Income from operations $ 19,313 (1) Direct operating expenses include lease operating and workover expense, gathering, processing and transportation expense, production taxes and depreciation, depletion and amortization expense. Included in general and administrative expenses in the consolidated statement of operations are transaction costs, including legal, accounting, valuation and other fees incurred to complete the acquisition, totaling $13.7 million, of which $12.4 million and $1.3 million were incurred during the years ended December 31, 2018 and 2017, respectively. Pro Forma Information (unaudited) For the years ended December 31, 2018, the pro forma financial information represents the combined results for the Company and the properties acquired as if the acquisition had occurred January 1, 2018. For the year ended December 31, 2018 the pro forma revenue and loss before income taxes was $174.7 million and $(7.7) million, respectively. This pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. There were no material dispositions in 2018. |
ASSETS HELD FOR SALE
ASSETS HELD FOR SALE | 12 Months Ended |
Dec. 31, 2019 | |
ASSETS HELD FOR SALE. | |
ASSETS HELD FOR SALE | NOTE 4 — ASSETS HELD FOR SALE The consolidated balance sheet includes assets and liabilities related to assets held for sale, comprised of the following as of December 31, 2018 (in thousands): Assets held for sale: December 31, 2018 Oil and gas properties - Dimmit County, Texas $ 23,471 Liabilities related to assets held for sale: Asset retirement obligations (193) Net assets held for sale $ 23,278 The Dimmit County assets were divested in October 2019. See Note 3. As of December 31, 2019, the Company’s balance sheet did not include assets or liabilities related to assets held for sale. Impairment of Assets Held for Sale For the years ended December 31, 2019 and 2018, the Company recorded impairment expense of $10.0 million and $43.0 million, respectively, related to assets held for sale as discussed in Note 11. |
ACCRUED LIABILITIES
ACCRUED LIABILITIES | 12 Months Ended |
Dec. 31, 2019 | |
ACCRUED LIABILITIES | |
ACCRUED LIABILITIES | NOTE 5 — ACCRUED LIABILITIES The following is a summary of accrued liabilities as of December 31, 2019 and 2018 (in thousands): December 31, 2019 2018 Oil and natural gas properties: Capital expenditures $ 4,168 $ 12,879 Re-fracture liability 764 900 Lease operating and workover expenses and other 7,393 6,586 Accrued interest payable 6,885 458 General and administrative expense 6,894 4,462 Finance lease liabilities 305 — Total accrued liabilities $ 26,409 $ 25,285 The Company entered into an agreement with Schlumberger Limited (“Schlumberger”) to re ‐ fracture five Eagle Ford wells in 2016. Under the terms of the agreement, Schlumberger will be paid for the services, plus a premium (if applicable), from the cash flow resulting from the incremental production generated by the re ‐ fractured wells above the forecasted base production prior to the re ‐ fracture work. The term of the agreement is five years and expires in 2021. The estimate of the remaining payout amount requires judgements regarding future production, pricing, operating costs and discount rates. The estimate of the related current liability is included above as the re-fracture liability. In addition, the Company recorded a long term liability related to the refracture services of $0.7 million and $1.1 million as of December 31, 2019 and 2018, respectively, which is included in other long-term liabilities on the consolidated balance sheets. |
LEASES
LEASES | 12 Months Ended |
Dec. 31, 2019 | |
LEASES | |
LEASES | NOTE 6 – LEASES Lease Accounting Adoption and transition Effective January 1, 2019, the Company began accounting for leases in accordance with ASC 842, which requires lessees to recognize lease liabilities and right-of-use assets on the balance sheet for contracts that provide lessees with the right to control the use of identified assets for periods of greater than 12 months. Prior to January 1, 2019, the Company accounted for leases in accordance with ASC Topic 840, Leases (“ASC 840”), under which operating leases were not recorded on the balance sheet. Adoption of ASC 842 resulted in the recognition of lease liabilities of $11.5 million and right-of-use assets (“ROU”) of $11.4 million related to the Company’s operating leases on its consolidated balance sheet, and did not result in the Company recognizing a cumulative-effect adjustment to accumulated deficit, at January 1, 2019. In connection with the adoption of ASC 842 effective January 1, 2019, the Company applied the following transition practical expedients: · A package of practical expedients which allowed the Company, for its arrangements in existence prior to the January 1, 2019 application date, to not reassess (1) whether an arrangement was or contained a lease at its commencement date, (2) its previous conclusions regarding classification of a lease as an operating or finance lease at its commencement date, and (3) initial direct costs as recorded; · A practical expedient which allowed the Company, for its arrangements in existence prior to the January 1, 2019 application date, to not reassess its accounting for land easement arrangements not previously accounted for as leases; and · A practical expedient to use hindsight in assessing the lease term and impairment. The scope of ASC 842 excludes leases to explore for or use minerals, oil, natural gas, and similar non-regenerative resources. However, leases of equipment used to explore for natural resources (for example, drilling equipment) are not part of this scope exception . Accounting Policies for Leases The Company has made the following policy elections related to accounting for its leases under ASC 842: · Exemption from recognition and measurement provisions for short-term leases (a lease that at commencement has a lease term of 12 months or less) in all classes of assets; · Election to not separate nonlease components, such as amounts for related taxes and common area maintenance charges, in certain classes of assets, including its office facilities and equipment, amine and compression equipment, land right-of-way and surface use arrangements, and employee lodging; and · Election to apply general provisions and discount rates to certain portfolios of leases with reasonably similar characteristics. The Company determines whether an arrangement is, or contains, a lease based on the substance of the arrangement at its inception. The Company applies judgment in analyzing the arrangement to determine whether it conveys an enforceable right to control the use of an identified asset or assets for a period of time in exchange for consideration. For the Company as lessee, this assessment includes consideration of whether it has the right to obtain substantially all of the economic benefits from the use of the identified asset, together with the right to direct the use of the asset, and whether there is an enforceable obligation for it to exchange consideration for those rights. The Company assesses the classification of its lease arrangements upon commencement of the lease by determining whether the lease contains any one of the following criteria for classification as a finance lease, and if it does not, it is classified as an operating lease: · Transfer of ownership of the underlying asset to the Company by the end of the lease term; · An option to purchase the underlying asset that the Company is reasonably certain to exercise; · A lease term that is for the major part of the remaining economic life of the underlying asset; · A present value of the sum of lease payments and lessee’s guaranteed residual value equal to or in excess of substantially all of the fair value of the underlying asset; or · An underlying asset that is of such a specialized nature that it is expected to have no alternative use to the lessor at the end of the lease term. Operating lease cost is recognized on a straight-line basis over the lease term. Finance lease cost is recognized based on the effective interest method for the lease liability and straight-line amortization of the ROU asset, resulting in more cost being recognized in earlier periods. All payments for short-term leases are recognized on a straight-line basis over the lease term. Short-term lease cost excludes amounts for rental of equipment for periods less than thirty days in duration. Leasing Arrangements and Significant Assumptions and Judgments The Company enters into leases as lessee to conduct its normal operations. The Company has operating leases primarily for its use of compression equipment, a drilling rig, land right of way and surface use arrangements, office facilities, and other production equipment. The Company has finance leases for its use of field vehicles and office equipment. Most of the Company’s leasing arrangements include extension and termination options, including evergreen provisions, all of which provide the Company flexibility in retaining the underlying facilities and equipment, as well as some protection from future price variability. The Company recognizes options to extend or terminate its leases as part of its assessment of the lease term, when it is reasonably certain to exercise the option. The Company’s leases are typically not significant enough individually or in the aggregate to impose or affect restrictions in its borrowing capacity or financial covenants. Some of the Company’s contracts have pricing that is variable within a range based on throughput, others have a set rate increase at predetermined intervals, and others are silent as to future increases or have a rate that is undefined for the variable components. The Company’s leases do not have future variable payments related to indices. For contracts with throughput provisions subject to a range, future payments have been included in the calculation of the lease liabilities at the contract minimum rate. Future payment increases for leases with set rate increases have been incorporated into the calculation of the lease liabilities, including the escalations. Future variable payments such as for movement or demobilization of the underlying leased asset have typically been excluded from the calculation of the lease liabilities unless they are determinable, and are expensed as incurred. The Company has applied judgment to determine the lease term for some of its lease contracts which include renewal or termination options. Certain of the Company’s leases include an “evergreen” provision that allows the contract term to continue on a month-to-month or year-to-year basis following expiration of the initial term included in the contract. For leases with an evergreen provision that renewed during the year ended December 31, 2019, the term of the lease was re-assessed by the Company and determined to be the non-cancelable period in the contract, plus the period beyond that cancellation period that the Company believes it is reasonably certain it will need the equipment for operational purposes. This re-assessment affects the value of ROU assets and lease liabilities recognized in the balance sheets at December 31, 2019. The Company has also applied judgment in determining the discount rate to apply to its lease calculations. The lease liabilities and corresponding ROU assets have been discounted using the Company’s incremental borrowing rate, which has been derived from rates expected to be available under the Company’s Revolving Credit Facility, using available borrowing base capacity and forward curve information over periods comparable to the term of each lease. Lease Recognition and Measurement The ROU asset is initially measured to be equal to the lease liability and adjusted for any lease incentives received and initial direct costs and lease prepayments incurred. Subsequently, the ROU asset is measured at cost less any accumulated amortization and adjusted for certain remeasurements of the lease liability or impairments of the ROU asset. The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is re-measured when there is a change in future lease payments arising from a change in the Company’s plans with respect to exercise of options included in terms of the lease, or a modification to the lease arrangement. In the event that there is a modification to a lease arrangement, a determination of whether the modification results in a separate lease arrangement being recognized is made. The Company also considers the impact of the modification on classification of the lease. If the modification results in the recognition of a separate lease arrangement, due to an increase in scope of a lease for example through additional underlying leased assets being added and a commensurate increase in lease payments, the Company measures the new arrangement separately, accounting for it as a new lease. If the modification does not result in a separate lease arrangement, for example due to an extension of the lease term that does not exceed the life of the underlying asset, the Company re-measures the remaining lease liability from the effective date of the modification using the re-determined lease term, remaining future lease payments and applicable discount rate. Lease Supplemental Disclosures The following tables present the carrying amounts and classifications of the Company’s ROU assets (net of accumulated amortization) and estimated lease liabilities as of December 31, 2019 (in thousands): Right-of-use assets Balance Sheet Location December 31, 2019 Operating lease right-of-use assets Operating lease right-of-use assets $ 17,331 Finance lease right-of-use assets Other property and equipment, net of accumulated depreciation 747 Total right-of-use assets $ 18,078 Lease liabilities Balance Sheet Location December 31, 2019 Operating lease liabilities - current Operating lease liabilities - current $ 7,720 Operating lease liabilities - non-current Operating lease liabilities - non-current 9,611 Finance lease liabilities - current Accrued expenses Finance lease liabilities - non-current Other long-term liabilities Total lease liabilities $ 18,065 Information regarding the Company’s lease terms and discount rates as of December 31, 2019 are as follows: Weighted Average Remaining Lease Term (years) Operating Leases 5.22 Finance Leases 2.58 Weighted Average Discount Rate Operating Leases Finance Leases The following summarizes total lease cost, which includes amounts recognized on the consolidated statement of operations and other comprehensive income (loss) and amounts capitalized related to the Company’s leases (in thousands): Year ended December 31, 2019 Operating lease cost (1) $ 11,729 Finance lease cost: Amortization of right-of-use assets $ 187 Interest on lease liabilities 20 Total finance lease cost $ 207 Short-term lease cost $ 1,065 Variable lease cost $ 1,395 Sublease income $ 150 (1) Operating lease cost of $6.3 million related to the Company’s drilling rig was capitalized to oil and gas properties on the consolidated balance sheet and will be depleted in accordance with the Company’s policies. The following summarizes supplemental cash flow information related to the Company’s leases (in thousands): December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 5,271 Operating cash flows from finance leases $ 20 Investing cash flows from operating leases $ 6,308 Financing cash flows from finance leases $ 187 Supplemental non-cash information on lease liabilities arising from right of use assets Operating lease liability additions $ 17,358 Finance lease liability additions $ 640 The Company’s lease obligations as of December 31, 2019 will mature as follows (in thousands): Year Ending December 31, Operating Leases Finance Leases 2020 $ 7,848 $ 312 2021 4,061 305 2022 2,819 150 2023 2,192 12 2024 845 - Thereafter 1,481 - Total lease payments $ 19,246 $ 779 Less: Interest (1,915) (45) Total discounted lease payments $ 17,331 $ 734 As of December 31, 2018, future minimum contractual payments for long-term leases under the scope of ASC 840 were as follows (in thousands): Year Ending December 31, Drilling Rig Operating Leases Capital Leases 2019 $ 4,106 $ 2,087 $ 97 2020 - 1,376 98 2021 - 602 90 2022 - 141 15 2023 - 83 12 Thereafter - 964 - Total lease payments $ 4,106 $ 5,253 $ 312 Less interest (26) Total discounted lease payments $ 286 Capital leases at December 31, 2018 included $0.2 million related to field vehicles and $0.1 million related to office equipment. Rent expense for the year ended December 31, 2018 was $3.6 million. |
LONG-TERM DEBT
LONG-TERM DEBT | 12 Months Ended |
Dec. 31, 2019 | |
LONG-TERM DEBT | |
LONG-TERM DEBT | NOTE 7 — LONG-TERM DEBT The following is a summary of long-term debt as of December 31, 2019 and 2018 (in thousands): December 31, 2019 2018 Revolving Facility $ 115,000 $ 65,000 Term Loan 250,000 250,000 Total long-term debt 365,000 315,000 Deferred financing fees, net of accumulated amortization (11,510) (14,196) Total credit facilities, net of deferred financing fees $ 353,490 $ 300,804 On April 23, 2018, contemporaneous with the closing of its Eagle Ford acquisition, the Company entered into the $250.0 million syndicated Term Loan with Morgan Stanley Energy Capital, as administrative agent, and the syndicated Revolving Facility with Natixis, New York Branch, as administrative agent, with initial availability of $87.5 million ($250.0 million face). The proceeds of the refinanced debt facilities were used to retire the Company’s previous credit facilities of $192.0 million, repay the Company’s production prepayment of $11.8 million and pay deferred financing fees on the Term Loan and Revolving Facility of $16.7 million, with the balance being used for the Company’s working capital needs at the time of closing the acquisition. The Revolving Facility and Term Loan are secured by certain of the Company’s oil and gas properties. The Revolving Facility is subject to a borrowing base, which is redetermined at least semi-annually; the next of such redeterminations will occur in the second quarter of 2020. The Revolving Facility will mature in October 2022, and the Term Loan will mature in April 2023. If, upon any downward adjustment of the borrowing base, the outstanding borrowings are in excess of the revised borrowing base, the Company may have to repay its indebtedness in excess of the borrowing base immediately, or in five monthly installments. As of December 31, 2019, the Company had letters of credit of $16.4 million outstanding on the Revolving Facility, and $38.6 million of available borrowing capacity. Interest on the Revolving Facility accrues at a rate equal to LIBOR, plus a margin, depending on the level of funds borrowed. As of December 31, 2019, the margin ranged from 2.25% to 3.25% (2.5% to 3.5% prior to May 2019). Interest on the Term Loan accrues at a rate equal to the greater of Subsequent to December 31, 2019, the Company entered into the fourth amendment to the Revolving Facility, which increased the borrowing base to $210 million (with elected borrowing commitments of $190 million), increased the maximum credit amount from $250 million to $500 million, revised the Leverage Ratio and Interest Coverage Ratio covenant (as reflected below) and appointed Toronto Dominion (Texas) LLC, as the administrative agent. Under the Revolving Facility, the Company is required to maintain the following financial ratios: · a minimum Current Ratio, consisting of consolidated current assets (as defined in the Revolving Facility) including undrawn borrowing capacity to consolidated current liabilities (as defined in the Revolving Facility), of not less than 1.0 to 1.0 as of the last day of any fiscal quarter; · a maximum Leverage Ratio, consisting of consolidated Total Debt to adjusted consolidated EBITDAX (as defined in the Revolving Facility), of not greater than 3.5 to 1.0 as of the last day of any fiscal quarter; and · a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Revolving Facility), of not less than 1.5 to 1.0 as of the last day of any fiscal quarter (for such time as there a similar covenant under the Company’s or SEI’s subordinated indebtedness). Under the Term Loan, the Company is required to maintain the following financial ratios: · a minimum Interest Coverage Ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Term Loan), of not less than 1.5 to 1.0 as of the last day of any fiscal quarter (for such time as there a similar covenant under the Company’s or SEI’s subordinated indebtedness); and · An Asset Coverage Ratio, consisting of Total Proved PV9% to Total Debt (as defined in the Term Loan agreement), of not less than 1.50 to 1.0. As of December 31, 2019 and 2018, the Company was in compliance with all restrictive financial and other covenants under the Revolving Facility and Term Loan. The Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception. The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the Revolving Facility and Term Loan agreements. The Company obtained waivers from its Revolving Facility and Term Loan lenders on May 8, 2020 and May 11, 2020, respectively, to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and with respect to the defaults arising from a failure to deliver audited consolidated financial statements for the year ended December 31, 2019 and related reports and certificates by the applicable deadline. These waivers were effective as of April 29, 2020, subject to the conditions set forth in the waivers. Refer to Note 1 and Note 15 for additional information. |
ASSET RETIREMENT OBLIGATIONS
ASSET RETIREMENT OBLIGATIONS | 12 Months Ended |
Dec. 31, 2019 | |
ASSET RETIREMENT OBLIGATIONS | |
ASSET RETIREMENT OBLIGATIONS | NOTE 8 — ASSET RETIREMENT OBLIGATIONS The Company’s asset retirement obligations represent the present value of estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage, and land restoration in accordance with applicable lease terms, local, state and federal laws. The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2019 and 2018 (in thousands): December 31, 2019 2018 Balance, beginning of year $ 3,489 $ 1,549 Additional liability incurred 145 195 Obligations settled (85) (29) Obligations on assets acquired — 1,522 Obligations on assets sold (232) — Accretion expense 336 252 Balance, end of year $ 3,653 $ 3,489 Liabilities related to assets held for sale $ — $ 193 Long-term 3,653 3,296 $ 3,653 $ 3,489 |
INCOME TAXES
INCOME TAXES | 12 Months Ended |
Dec. 31, 2019 | |
INCOME TAXES | |
INCOME TAXES | NOTE 9 — INCOME TAXES Income taxes are computed using the asset and liability method. Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities, their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date. The income tax provision is comprised of the following (in thousands): Year Ended December 31, 2019 2018 Current income tax expense - Federal $ — $ 2,301 Deferred income tax expense (benefit) Federal (8,281) (5,555) State 11 318 Foreign (503) (2,929) Total deferred income tax expense (benefit) (8,773) (8,166) Valuation Allowance Income tax provision (benefit) 4,255 19,822 Total income tax expense (benefit) $ (4,518) $ 13,957 A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands): Year Ended December 31, 2019 2018 Income tax benefit at the federal statutory rate $ (9,263) $ (1,885) State income taxes - net of federal income tax benefits 10 290 Stock-based compensation 114 839 Nondeductible expenses 519 1,055 Change in valuation allowance 4,255 19,822 Foreign tax rates (166) (877) Australian tax losses on U.S. Restructuring — (3,284) Deemed interest payment due to U.S. restructuring — (4,350) U.S. withholding tax net of foreign tax credit — 2,301 Other 13 46 Total income tax expense (benefit) $ (4,518) $ 13,957 In 2018 in connection with the equity raise to fund the Company’s Eagle Ford acquisition, the Company had a greater than 50% ownership change pursuant to Section 382 of the Internal Revenue Code. As a result of the ownership change, the Company’s ability to use pre-change net operating losses (“NOLs”) and credits against post-change taxable income is limited to an annual amount plus any built-in gains recognized within five years of the ownership change. The Company’s use of pre-change losses of $248.5 million will be limited to approximately $42.3 million. Accordingly, the Company recorded a valuation allowance to reduce its deferred tax assets. As of December 31, 2019, the Company had U.S. federal NOL carryforwards of $292.4 million. The Company also has various state NOL carryforwards. The determination of the state NOL carryforwards is dependent upon apportionment percentages and state laws that can change from year to year and that can thereby impact the amount of such carryforwards. If unutilized, the majority of the federal NOLs will expire between 2033 and 2037 and the state NOLs will expire between 2021 and 2037. Any federal NOLs generated in 2018 or subsequent do not expire. The Company also has Australian NOLs of $26.2 million that do not expire. The Company completed a restructuring of its U.S. subsidiaries during the year ended December 31, 2018. The restructuring resulted in recognized tax losses under Australian tax law of $15.6 million creating loss carryover available to offset future income. As the Company does not believe it is more likely than not that these carryovers will be utilized in the future, it has recorded a valuation allowance against the Australian deferred tax assets. Additionally, the restructuring resulted in a deemed payment of interest from the U.S. subsidiaries to the Company of $20.7 million which required the Company to pay a $2.3 million withholding tax. In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, available taxes in carryback periods, projected future taxable income, and tax planning strategies in making this assessment. Judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other deferred tax assets will be utilized prior to their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense. The tax effects of temporary differences that give rise to significant components of the deferred income tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands): December 31, 2019 2018 Deferred tax assets: Net operating loss carryforward $ 76,624 $ 70,560 Business interest carryforward 10,474 7,054 Stock-based compensation 93 102 Statutory depletion carryforward 2,927 2,977 Unrealized (gain) loss on commodity derivative 1,147 (6,453) Lease obligations 3,735 — Property, plant and equipment 82 (122) Other assets 524 1,688 Total deferred tax assets 95,606 75,806 Valuation allowance (64,898) (60,643) Deferred tax assets, net 30,708 15,163 Deferred tax liabilities: Basis of oil and gas properties (33,950) (26,819) Lease assets (3,896) — Total deferred tax liabilities (37,846) (26,819) Deferred tax liabilities, net $ (7,138) $ (11,656) As of December 31, 2019, the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards, and would not result in significant interest expense or penalties. The Company’s federal and state tax returns filed since December 31, 2016 and December 31, 2015, respectively, remain subject to examination by tax authorities. The Company's Australian tax returns filed since December 31, 2015 also remain subject to examination. On March 27, 2020, President Trump signed into U.S. federal law the CARES Act, which is aimed at providing emergency assistance and health care for individuals, families, and businesses affected by the COVID-19 pandemic and generally supporting the U.S. economy. The CARES Act, among other things, includes provisions relating to refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, alternative minimum tax credit (“AMT”) refunds, modifications to the net interest deduction limitations and technical corrections to tax depreciation methods for qualified improvement property. In particular, the CARES Act, (i) eliminates the 80% of taxable income limitation by allowing corporate entities to fully utilize NOLs to offset taxable income in 2018, 2019 or 2020, (ii) allows for |
DERIVATIVE FINANCIAL INSTRUMENT
DERIVATIVE FINANCIAL INSTRUMENTS | 12 Months Ended |
Dec. 31, 2019 | |
DERIVATIVE FINANCIAL INSTRUMENTS | |
DERIVATIVE FINANCIAL INSTRUMENTS | NOTE 10 — DERIVATIVE FINANCIAL INSTRUMENTS Commodity Derivatives The Company uses derivative instruments to mitigate volatility in commodity prices. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future cash flow from favorable price changes. The Company’s policy is to hedge at least 50% of its the reasonably projected oil & gas production from the Proved Reserves classified as “Developed Producing Reserves” for a rolling 36 month period, but not more than 85% of the reasonably projected production from the Proved Reserves for a rolling 24 months and not more than 75% of the reasonably projected production from the Proved Reserves for months 25-60, as required by its Revolving Facility agreement. As of December 31, 2019, the Company has primarily entered into oil and gas swaps and collars and oil basis swaps. For collars, the Company receives the difference between the published index price and a floor price if the index price is below the floor price, or pays the difference between the ceiling price and the index price if the index price is above the ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling prices. By using a collar, the minimum and maximum prices on the underlying production are fixed. The oil basis swaps are settled based on the difference between a published index price minus a fixed differential and the applicable local index price under which the underlying production is sold. By using a basis swap, the Company has fixed the differential between the published index price and certain of our physical pricing points. The basis swaps fix the price differential between the WTI NYMEX (Cushing Oklahoma) price and the WTI Houston Argus price. A summary of the Company’s commodity derivative positions as of December 31, 2019 follows: Oil Swaps - WTI (1) Year Volumes (Bbl) Weighted Average Price per Bbl 2020 $ 57.17 2021 $ 54.84 Oil Collars - WTI Year Volumes (Bbl) Weighted Average Price per Bbl - Floor Weighted Average Price per Bbl - Ceiling 2020 $ 54.47 $ 61.82 2021 $ 45.00 $ 65.00 2022 $ 40.00 $ 66.00 2023 $ 40.00 $ 63.10 Oil Three-Way Collars - WTI Year Volumes (Bbl) Weighted Average Price per Bbl - Floor Sold Weighted Average Price per Bbl - Floor Purchased Weighted Average Price per Bbl - Ceiling 2020 $ 35.00 $ 50.00 $ 59.60 2021 $ 35.00 $ 50.00 $ 57.50 2022 $ 35.00 $ 50.00 $ 56.90 Propane Calls Sold - OPIS Propane Mont Belvieu - TET (2) Year Volumes (Bbl) Weighted Average Price per Bbl 2020 $ 0.70 Oil Basis Swaps - WTI-HOU (3) Year Volumes (Bbl) Weighted Average Differential per Bbl 2020 $ 2.98 2021 $ 2.53 Natural Gas Swaps Price Swaps - HH (4) Price Swaps - HSC (5) Year Volumes (MMBtu) Weighted Average Price per MMBtu Volumes (MMBtu) Weighted Average Price per MMBtu 2020 $ 2.70 $ 2.53 2021 $ 2.69 $ 2.50 2022 $ 2.76 $ 2.54 2023 $ 2.64 Natural Gas Collars - HH Year Volumes (MMBtu) Weighted Average Price per MMBtu - Floor Weighted Average Price per MMBtu - Ceiling 2020 $ 2.50 $ 2.95 HSC Year Volumes (MMBtu) Weighted Average Price per MMBtu - Floor Weighted Average Price per MMBtu - Ceiling 2020 $ 2.60 $ 2.91 Subsequent to December 31, 2019, the Company entered into the following commodity derivative positions: Oil Swaps Price Swaps - WTI Year Volumes (Bbl) Weighted Average Price per Bbl 2020 $ 49.39 2021 $ 48.38 Natural Gas Swaps Price Swaps - HH Year Volumes (MMBtu) Weighted Average Price per MMBtu 2021 $ 2.67 The following is a list of index prices: (1) WTI crude oil as quoted on NYMEX. (2) Mont Belvieu – Texas Eastern Transmission (“TET”) propane as quoted by Oil Price Information Service (“OPIS”). (3) WTI Houston Argus (“WTI-HOU”) crude oil as quoted by Argus US Pipeline. (4) Henry Hub (“HH”) natural gas as quoted on the NYMEX. (5) Houston Ship Channel (“HSC”) natural gas as quoted in Platt’s Inside FERC. Interest Rate Derivatives A summary of the Company’s interest rate swaps as of December 31, 2019 follows (notional amount in thousands): Portion of Term Term Loan Effective Date Termination Date Notional Amount Fixed Rate (1) Face Amount July 11, 2019 July 11, 2020 $ 3.016 % 75 % July 11, 2020 July 11, 2021 $ 3.072 % 50 % July 11, 2021 July 11, 2022 $ 3.061 % 50 % July 13, 2022 May 23, 2023 $ 3.042 % 50 % (1) Each contract has a 1% floor, consistent with the structure of the Term Loan. Offsetting of Derivative Assets and Liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The following tables summarize the location and fair value amounts of all the Company’s derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands): December 31, 2019 Gross Gross Net Recognized Recognized Amounts Fair Value Not Designated as ASC 815 Hedges Balance Sheet Classification Assets/Liabilities Offset Assets/Liabilities DERIVATIVE ASSETS : Current: Derivative financial instruments — commodity contracts Derivative assets $ 2,863 $ (1,648) $ 1,215 Derivative financial instruments — interest rate swaps Derivative assets 8 (8) — Long-term: Derivative financial instruments — commodity contracts Derivative assets 2,637 (1,759) 878 Derivative financial instruments — interest rate swaps Derivative assets 377 (377) — Total derivative assets 5,885 2,093 DERIVATIVE LIABILITIES : Current: Derivative financial instruments — commodity contracts Derivative liabilities 3,946 (1,648) 2,298 Derivative financial instruments — interest rate swaps Derivative liabilities 2,104 (8) 2,096 Total current derivative liabilities 6,050 4,394 Long-term: Derivative financial instruments — commodity contracts Derivative liabilities 1,761 (1,759) 2 Derivative financial instruments — interest rate swaps Derivative liabilities 4,044 (377) 3,667 Total long-term derivative liabilities 5,805 3,669 Total derivative liabilities 11,855 8,063 $ (5,970) $ (5,970) December 31, 2018 Gross Gross Net Recognized Recognized Amounts Fair Value Not Designated as ASC 815 Hedges Balance Sheet Classification Assets/Liabilities Offset Assets/Liabilities DERIVATIVE ASSETS : Current: Derivative financial instruments — commodity contracts Derivative assets $ 24,877 $ (562) $ 24,315 Derivative financial instruments — interest rate swaps Derivative assets 5,081 (5,081) — Long-term: Derivative financial instruments — commodity contracts Derivative assets 8,403 (400) 8,003 Derivative financial instruments — interest rate swaps Derivative assets 11,142 (11,142) — Total derivative assets 49,503 32,318 DERIVATIVE LIABILITIES : Current: Derivative financial instruments — commodity contracts Derivative liabilities 787 (562) 225 Derivative financial instruments — interest rate swaps Derivative liabilities 5,292 (5,081) 211 Total current derivative liabilities 6,079 436 Long-term: Derivative financial instruments — commodity contracts Derivative liabilities 1,051 (400) 651 Derivative financial instruments — interest rate swaps Derivative liabilities 13,069 (11,142) 1,927 Total long-term derivative liabilities 14,120 2,578 Total derivative liabilities 20,199 3,014 $ 29,304 $ 29,304 Gain (Loss) Recognized in Income Year Ended December 31, Not designated as ASC 815 Hedges Statement of Operations Classification 2019 2018 Foreign currency Gain on foreign currency derivative financial instruments $ - $ 6,838 Commodity contracts Gain (loss) on commodity derivative financial instruments (20,542) 40,216 Interest rate swap Interest expense (4,270) (2,435) $ (24,812) $ 44,619 Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk related contingent features. Most of the counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions and that are lenders under Sundance’s credit agreement. The Company uses credit agreement participants to hedge with, since these institutions are secured equally with the holder’s of Sundance’s bank debt, which eliminates the need to post collateral when Sundance is in a derivative liability position. The Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations. Refer to Note 11 for additional information regarding the valuation of derivative instruments. |
FAIR VALUE MEASUREMENT
FAIR VALUE MEASUREMENT | 12 Months Ended |
Dec. 31, 2019 | |
FAIR VALUE MEASUREMENT | |
FAIR VALUE MEASUREMENT | NOTE 11 — FAIR VALUE MEASUREMENT The Company follows FASB ASC Topic 820 – Fair Value Measurement and Disclosure which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows: Level 1: Quoted prices (unadjusted) for identical assets or liabilities in active markets. Level 2: Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability and inputs that are derived from observable market data by correlation or other means. Level 3: inputs for the asset or liability that are not based on observable market data (unobservable inputs). The Level within which the financial asset or liability is classified is determined based on the lowest level of significant input to the fair value measurement. The financial assets and liabilities measured at fair value on a recurring basis in the consolidated balance sheets are grouped into the fair value hierarchy as follows (in thousands): December 31, 2019 Level 1 Level 2 Level 3 Total Assets measured at fair value Derivative commodity contracts $ — $ 2,093 $ — $ 2,093 Liabilities measured at fair value Derivative commodity contracts — (2,300) — (2,300) Derivative interest rate swaps — (5,763) — (5,763) — (8,063) — (8,063) Net fair value $ — $ (5,970) $ — $ (5,970) December 31, 2018 Level 1 Level 2 Level 3 Total Assets measured at fair value Derivative commodity contracts $ — $ 32,318 $ — $ 32,318 Liabilities measured at fair value Derivative commodity contracts — (876) — (876) Derivative interest rate swaps — (2,138) — (2,138) — (3,014) — (3,014) Net fair value $ — $ 29,304 $ — $ 29,304 During the years ended December 31, 2019 and 2018, there were no transfers between Level 1 and Level 2 fair value measurements, and no transfer into or out of Level 3 fair value measurements. Measurement of Fair Value a) Derivatives The Company’s derivative instruments consist of commodity contracts (primarily swaps and collars) and interest rate swaps. The Company utilizes present value techniques and option-pricing models for valuing its derivatives. Inputs to these valuation techniques include published forward prices, volatilities, and credit risk considerations, including the incorporation of published interest rates and credit spreads. All of the significant inputs are observable, either directly or indirectly; therefore, the Company’s derivative instruments are included within the Level 2 fair value hierarchy. b) Credit Facilities As of December 31, 2019 and 2018, the Company had $250 million and $115 million, and $250 million and $65 million of principal debt outstanding on its Term Loan and Revolving Facility, respectively. The Company estimated that the fair value of its Term Loan at December 31, 2019 was $249 million. The fair value of the Term Loan was determined by using a discounted cash flow model using a discount rate that reflects the Company’s assumed borrowing rate at the end of the reporting period. The carrying value of the Company’s Revolving Facility approximates its fair value as its variable interest rate is tied to current market rates and the applicable margins of 2.25%‑3.25% approximate market rates. c) Other Financial Instruments The carrying amounts of cash, accounts receivable, accounts payable, and accrued liabilities approximate fair value due to their short-term nature. d) Non-recurring Fair Value Measurements The Company applies the provisions of the fair value measurement standard on a non-recurring basis to its non-financial assets and liabilities, including oil and gas properties and assets held for sale. Assets held for sale. Oil and gas properties classified as held for sale, including any corresponding asset retirement obligation, are valued using a market approach, based on an estimated net selling price. If an estimated selling price is not available, the Company utilizes valuation techniques depending on whether the properties are proved or unproved. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. Net Carrying Value as of Fair Value Measurements Using (in thousands) December 31, 2018 Level 1 Level 2 Level 3 Assets held for sale $ 23,471 $ — $ — $ 23,471 The Company wrote down its Dimmit County oil and gas properties, which were classified as held for sale, to the expected purchase price proceeds, less anticipated external broker marketing costs. The Company’s estimate of the expected purchase price proceeds was based upon comparable transaction data. The Company disposed of the Dimmit County properties in October 2019. Business Combinations. In estimating the fair values of assets acquired and liabilities assumed, the Company makes various assumptions, which include Level 3 inputs. The most significant assumptions relate to the estimated fair values assigned to proved developed producing, proved developed non-producing, proved undeveloped and unproved oil and gas properties. To derive fair value, the Company prepares estimates of oil and gas reserves, applying forward strip prices to reserve quantities acquired, and estimating future operating and development costs to arrive at an estimate of undiscounted future net revenues. For estimated proved reserves, the future net revenues are discounted using a market-based weighted-average cost of capital (“WACC”) rate at the time of the acquisition. The market-based WACC rate is subject to additional project-specific risk factors. To compensate for the inherent risk of estimating and valuing unproved properties, the Company reduces the discounted future net revenues of probable and possible reserves by higher discount rates or additional risk-weighting factors. Additionally, for acquisitions with significant unproved properties, the Company reviews comparable purchases and sales of oil and gas properties within the same regions and uses that data as a basis for fair market value. |
EARNINGS PER SHARE
EARNINGS PER SHARE | 12 Months Ended |
Dec. 31, 2019 | |
EARNINGS PER SHARE | |
EARNINGS PER SHARE | NOTE 12 — EARNINGS PER SHARE The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data): Year Ended December 31, 2019 2018 Net loss $ (39,590) $ (22,933) Weighted average shares (1): Weighted average common shares outstanding, basic 6,874,170 5,236,524 Diluted effect of incremental shares related to restricted share units (2) — — Weighted average common shares outstanding, diluted 6,874,170 5,236,524 Net loss per share: Basic and diluted $ (5.76) $ (4.38) (1) All share numbers have been retroactively adjusted for the 2019 and 2018 periods to reflect the Company’s one for 100 share consolidation in November 2019, as described in Note 13. (2) For the year ended December 31, 2019, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes anti-dilutive shares of 320 shares of service-based awards. For the year ended December 31, 2018, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes anti-dilutive shares of 786 shares of service-based awards. |
EQUITY
EQUITY | 12 Months Ended |
Dec. 31, 2019 | |
EQUITY | |
EQUITY | NOTE 13 — EQUITY Reverse Stock Split In conjunction with the Company’s Redomiciliation, the Company acquired all of the outstanding ordinary shares of SEAL on the basis of one share of the Company’s stock for every 100 ordinary shares outstanding, which had the effect of a 1-for-100 reverse stock split. On the effective date of the Redomiciliation, the number of ordinary outstanding shares was reduced from 687 million to 6.9 million. All share and per share amounts in these consolidated financial statements and related notes for periods prior to the Redomiciliation have been retroactively adjusted to reflect the effect of the exchange ratio. Equity Offerings During 2018, the Company issued 5,614,446 shares in connection with a $243 million capital raise (net of offering costs), proceeds of which were used to complete the 2018 acquisition of Eagle Ford oil and gas properties. Stock-Based Compensation For the years ended December 31, 2019 and 2018, the Company recognized stock-based compensation expense of $0.5 million and $0.5 million, respectively, related to RSUs (equity-settled). During the years ended December 31, 2019 and 2018, the Board of Directors awarded 38,373 and 71,175 RSUs, respectively, to certain employees. These awards were made in accordance with SEAL’s Plan. In connection with the Redomiciliation, in November 2019 Sundance Energy Inc. assumed SEAL’s obligations with respect to the settlement of the RSUs that were granted pursuant to the Plan prior to the effective date of the Redomiciliation. Accordingly, the RSUs will be settled in shares of common stock of Sundance Energy Inc. rather than ordinary shares of SEAL. Following the effective date of the Redomiciliation, no new awards or grants have been or will be made pursuant to the Plan. Historical RSU information is summarized below: Weighted Average Fair Value at Number of RSUs Grant Date Outstanding at December 31, 2017 33,804 $ 166.87 Granted 71,175 $ 18.80 Vested (6,916) $ 361.03 Forfeited (6,724) $ 198.37 Outstanding at December 31, 2018 91,339 $ 34.37 Granted 38,373 $ 20.31 Vested (1) (1,425) $ 61.56 Forfeited (43,358) $ 51.20 Outstanding at December 31, 2019 84,929 $ 22.97 (1) Includes 375 RSUs that have vested, but will be settled in 2020. Restricted Share Units on Issue Details of the RSUs outstanding as of December 31, 2019 and 2018: Number of RSUs Grant Date 2019 2018 March 15, 2016 (1) — 4,428 May 27, 2016 (1) — 4,342 June 29, 2016 (1) — 497 February 17, 2017 (1)(2) 3,411 4,572 May 25, 2017 (1)(2) 3,724 3,724 October 23, 2017 (1) 745 745 October 23, 2017 375 750 December 29, 2017 497 1,106 December 26, 2018 (3) 30,414 35,587 December 26, 2018 (4) 15,207 35,588 May 5, 2019 1,775 — May 5, 2019 (1) 5,325 — May 31, 2019 (3) 15,637 — May 31, 2019 (4) 7,819 — Total RSUs outstanding 84,929 91,339 (1) RSUs vest based on three‑year absolute total shareholder return (“ATSR”). (2) ATSR RSUs were evaluated for vesting subsequent to December 31, 2019. The vesting conditions were not met and the outstanding awards will be forfeited in 2020. (3) RSUs vest based on three-year total shareholder return (“TSR”) as compared to the XOP index. (4) Company performance-based RSUs vest based on 2019 and 2020 EBITDA per debt adjusted share and production per debt adjusted share. The following tables summarize the RSUs issued and their related grant date, fair value and vesting conditions. RSUs awarded during the year ended December 31, 2019: Fair Value at Grant Date Number of RSUs Grant Date Vesting Conditions May 5, 2019 1,775 $ 29.49 Vests on 3rd anniversary of award May 5, 2019 5,325 $ 16.35 0 % - 200% based on 3 year TSR as compared to the XOP index. May 31, 2019 15,637 $ 16.13 0 % - 200% based on 3 year TSR as compared to the XOP index. May 31, 2019 3,909 $ 24.92 0 % - 200% based on 2019 EBITDA per Debt Adjusted Share May 31, 2019 3,909 $ 24.92 0 % - 200% based on 2020 EBITDA per Debt Adjusted Share May 31, 2019 3,909 $ 24.92 0 % - 200% based on 2019 Production per Debt Adjusted Share May 31, 2019 3,909 $ 24.92 0 % - 200% based on 2020 Production per Debt Adjusted Share 38,373 The following tables summarize the RSUs issued and their related grant date, fair value and vesting conditions. RSUs awarded during the year ended December 31, 2018: Fair Value at Grant Date Number of RSUs Grant Date Vesting Conditions December 26, 2018 35,587 $ 16.44 0 % - 200% based on 3 year TSR as compared to the XOP index December 26, 2018 8,897 $ 21.16 0 % - 200% based on 2019 EBITDA per Debt Adjusted Share December 26, 2018 8,897 $ 21.16 0 % - 200% based on 2020 EBITDA per Debt Adjusted Share December 26, 2018 8,897 $ 21.16 0 % - 200% based on 2019 Production per Debt Adjusted Share December 26, 2018 8,897 $ 21.16 0 % - 200% based on 2020 Production per Debt Adjusted Share 71,175 Upon vesting, and after a certain administrative period, the RSUs are settled in newly issued common stock of the Company. Once settled, the RSUs are no longer restricted. |
COMMITMENTS AND CONTINGENCIES
COMMITMENTS AND CONTINGENCIES | 12 Months Ended |
Dec. 31, 2019 | |
COMMITMENTS AND CONTINGENCIES | |
COMMITMENTS AND CONTINGENCIES | NOTE 14 —COMMITMENTS AND CONTINGENCIES Marketing, Gathering, Processing and Transportation Commitments In connection with the Company’s 2018 acquisition, the Company entered into contracts with a large midstream company to gather, process, transport and market oil, NGL and natural gas production for the acquired properties. The contracts contain a Minimum Revenue Commitment (“MRC”) that requires payment of minimum annual fees for those services. Fixed fees are expensed as incurred and settled with the purchaser on a monthly basis. If, at the end of each calendar year, the Company fails to satisfy the MRC, the Company is required to pay a shortfall. The Company’s MRC for the years ended December 31, 2019 and 2018 totaled $15.8 million and $11.1 million, respectively, and it realized deficiency fees of $2.3 million and $2.8 million, respectively. The total remaining MRC by fiscal year are as follows (in thousands): 2020 2021 2022 Total Hydrocarbon gathering and handling agreement $ 14,297 $ 13,972 $ 6,675 $ 34,944 Crude oil and condensate purchase agreements 4,710 7,513 4,317 16,540 Gas processing agreement 2,017 - - 2,017 Gas transportation agreements 783 - - 783 Total MRC $ 21,807 $ 21,485 $ 10,992 $ 54,284 Cooper Basin Capital Commitments The Company has non-core interest in the petroleum exploration license 570 located in the Cooper Basin, a license located in Australia (PEL 570). The Company has a commitment to fund exploratory drilling in the Cooper Basin of up to approximately A$10.6 million (US$7.5 million) through 2022, of which A$7.1 million (US$5.0 million) has been incurred as of December 31, 2019, with a remaining commitment of A$3.5 million. (US$2.5 million). The exploratory drilling has not resulted in any proved reserves to date, and less than $0.1 million and $0.7 million incurred during the years ended December 31, 2019 and 2018 was recorded as exploration expense on the consolidated statement of operations. Litigation The Company is involved in various legal proceedings in the ordinary course of business, and recognizes a contingent liability when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. While the outcome of these lawsuits and claims cannot be predicted with certainty, it is the opinion of management that, as of the date of this report, it is not probable that these claims and litigation will have a material adverse impact on the Company, Accordingly, no material amounts for loss contingencies associated with litigation, claims or assessments have been accrued as of December 31, 2019 other than described below. In 2013, the Company sold its interests in a non-operated North Dakota property. During the year ended December 31, 2019, the Company recorded additional expense of $0.7 million for a litigation settlement with the Buyer within other expense (income), net on the consolidated statement of operations. The settlement was paid in January 2020. |
SUBSEQUENT EVENTS
SUBSEQUENT EVENTS | 12 Months Ended |
Dec. 31, 2019 | |
SUBSEQUENT EVENTS | |
SUBSEQUENT EVENTS | NOTE 15 — SUBSEQUENT EVENTS As discussed in Note 1, the Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception. The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the Revolving Facility and Term Loan agreements. The Company obtained waivers from its Revolving Facility and Term Loan lenders on May 8, 2020 and May 11, 2020, respectively, to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and with respect to the defaults arising from a failure to deliver audited consolidated financial statements for the year ended December 31, 2019 and related reports and certificates by the applicable deadline. These waivers were effective as of April 29, 2020, subject to the conditions set forth in the waivers. Under the Revolving Facility waiver, the Company may not draw any additional funds on the Revolving Facility until completion of the Company’s second quarter 2020 borrowing base redetermination. Under the Term Loan waiver, the Company agreed to amend certain provisions in the Term Loan, as to be mutually agreed with the Term Loan lenders, within 15 days from the execution date. The waiver under the Revolving Facility also provides for a right to require corresponding amendments of that facility manner, as requested by the administrative agent in its discretion. Failure to enter into such amendment with respect to the Term Loan within 15 days (or a similar amendment with respect to the Revolving Facility on the date the Term Loan is amended) would constitute an event of default under the credit facilities, in which case the amounts outstanding under the credit facilities could be accelerated and become immediately due and payable. While management believes that it will finalize such amendments within the required time frame, there can be no assurance that management’s efforts will result in any finalizing these amendments or the ultimate terms of any such amendments. With respect to the Term Loan, the Company has engaged in preliminary discussions regarding the terms of the required amendment. In addition, the Company has agreed to explore in good faith with its Term Loan lenders options to reduce the Company’s overall level of indebtedness and leverage and limit capital and general and administrative expenditures for some specified period of time. As described above, the lenders under the Revolving Facility may request corresponding amendments under the Revolving Facility. |
SUPPLEMENTAL DISCLOSURES ABOUT
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | 12 Months Ended |
Dec. 31, 2019 | |
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | |
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | NOTE 16 — SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) Costs Incurred The Company’s oil and gas activities for 2019 and 2018 were entirely within the United States. Costs incurred in oil and gas producing activities were as follows (in thousands): Year ended December 31, 2019 2018 Property acquisition costs Proved $ — $ 173,750 Unproved (1) 177 45,252 Exploration costs 335 2,789 Development costs (2) (3) 149,766 181,463 (1) Includes costs incurred related to its Dimmit County assets, which were classified as held for sale during 2018 through their sale in October 2019, of nil and $1.0 million during the years ended December 31, 2019 and 2018, respectively. (2) Development costs include $7.1 million and $12.9 million wells in-progress as of December 31, 2019 and 2018, respectively. These wells in-progress were either drilling, waiting on hydraulic fracturing or production testing. (3) Includes costs incurred related to its Dimmit County assets, which were classified as held for sale during 2018 through their sale in October 2019, of $8.4 million and $5.3 million during the years ended December 31, 2019 and 2018, respectively. SEC Oil and Gas Reserve Information Ryder Scott Company, L.P., an independent petroleum engineering consulting firm, prepared estimates of all of the Company’s proved reserve quantities and pre-tax future net cash flows discounted at 10% as of December 31, 2019 and 2018. Proved reserves are those quantities of oil and natural gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. There are numerous uncertainties inherent in estimating quantities of proved reserves and projecting future rates of production and the timing of development expenditures. The estimation of our proved reserves employs one or more of the following: production trend extrapolation, analogy, volumetric assessment and material balance analysis. Techniques including review of production and pressure histories, analysis of electric logs and fluid tests, and interpretations of geologic and geophysical data are also involved in this estimation process. The following reserve data represents estimates only and should not be construed as being exact. All such reserves are located in the continental United States. Natural Oil Gas NGL Total (MBbl) (MMcf) (MBbl) (MBoe) Proved reserves: January 1, 2018 27,987 59,409 9,190 47,079 Revisions of previous estimates (5,138) (14,257) (3,201) (10,716) Extensions and discoveries 7,577 12,889 2,179 11,904 Purchases of reserves in-place 30,474 55,367 8,801 48,503 Production (2,256) (4,534) (497) (3,508) Sales of reserves in-place (15) (33) - (21) December 31, 2018 58,629 108,841 16,472 93,241 Revisions of previous estimates (14,358) (27,504) (4,225) (23,168) Extensions and discoveries 23,018 52,297 7,915 39,649 Production (3,077) (5,768) (798) (4,836) Sales of reserves in-place (1,424) (6,962) (1,230) (3,814) December 31, 2019 62,788 120,904 18,134 101,072 Proved developed reserves: December 31, 2018 16,742 33,169 4,927 27,197 December 31, 2019 16,101 26,930 4,022 24,611 Proved undeveloped reserves December 31, 2018 41,887 75,672 11,545 66,044 December 31, 2019 46,687 93,974 14,112 76,461 Notable changes in proved reserves for the years ended December 31, 2019 and 2018 included the following: Proved Undeveloped Reserves As of December 31, 2019, the Company’s proved undeveloped reserves were approximately 76,461 MBoe, an increase of 10,417 MBoe over its December 31, 2018 proved undeveloped reserves estimate of approximately 66,044 MBoe. The change primarily resulted from proved undeveloped locations added in 2019 as result of the Company’s technical evaluation of wells drilled and completed in late 2018 and in 2019 on properties acquired in 2018 (extensions and discoveries totaled 36,535 MBoe during the year). As of December 31, 2018, the Company was still in the process of evaluating many of the undeveloped locations acquired in 2018. As of December 31, 2018 approximately half of the undeveloped locations in its development plan were on acreage acquired in the 2018 acquisition. The remainder of the December 31, 2018 proved undeveloped locations were on properties that the Company owned prior to the 2018 acquisition (legacy properties or legacy locations). As a result of the Company’s additional technical evaluation of the acquired properties during 2019, the focus of its development plan shifted to properties acquired in 2018 with higher projected returns. Approximately 19,881 MBoe primarily associated with approximately 50 proved undeveloped locations on legacy properties were removed and 80 locations on the acquired assets with 35,630 MBoe were added to the Company’s five-year development plan. During 2019, the Company converted 4,501 MBoe of proved undeveloped reserves to proved developed producing reserves. Over the next five years, the Company expects to fund future development costs of $1,173.2 million associated with proved undeveloped reserves with operating cash flows from its existing proved developed reserves, cash flows from proved undeveloped reserves converted to proved developed reserves and with capacity available under its Revolving Credit Facility as of December 31, 2019. Using December 31, 2019 SEC price assumptions, the Company’s undiscounted operating cash flows from its proved reserves are expected to be approximately $1,503.7 million over the next five years which is adequate to fund projected future development costs, administrative expenses and interest. The Company’s development plan does not contemplate a uniform conversion of proved undeveloped reserves. At December 31, 2019, the Company’s five-year development plan assumed a slower development pace in 2020 and 2021, which would allow operating cash flow to accumulate. The Company intends to use the accumulated cash flow to fund an increased pace of development in later years such that all remaining proved undeveloped locations would be developed within the five-year period. Revisions of Previous Estimates The Company’s previous estimates of Proved Reserves decreased by 23,168 MBoe in 2019. This decrease was primarily due to the removal of certain proved undeveloped legacy locations as they were no longer scheduled to be drilled within their initial five year window as a result of redirecting the Company’s development plan to focus on locations with better economics that were acquired in 2018. The Company’s previous estimates of Proved Reserves related to the Eagle Ford Formation decreased by 10,716 MBoe in 2018. This decrease was primarily due to the removal of certain proved undeveloped reserves as they were not planned to be drilled within their initial five year window as a result of redirecting drilling efforts toward more locations that were part of the 2018 acquisition. Extensions and Discoveries The Company had extensions and discoveries of 39,649 MBoe during 2019, which were primarily proved undeveloped reserves, that were the result of the Company’s technical evaluation of wells drilled and completed in late 2018 and in 2019 on properties acquired in 2018. The 2019 drilling program was focused primarily in Live Oak County, Texas, and, to a lesser extent, in McMullen and Atascosa Counties, Texas. The Company’s total proved undeveloped locations as of December 31, 2019 were relatively consistent with that of prior year as a result of the removal of proved undeveloped legacy locations discussed in revisions of previous estimates. The Company had extensions and discoveries of 11,904 MBoe during 2018, resulting from the 2018 drilling program primarily in Live Oak County, Texas, and, to a lesser extent, in McMullen and LaSalle Counties, Texas, targeting the Eagle Ford Formation. Purchase of Reserves In-Place The Company did not purchase any reserves in place during 2019. In 2018, the Company’s purchases of reserves in place were located in the Eagle Ford in South Texas. Sales of Reserves In-Place During 2019, the Company’s sales of reserves were located in Dimmit County, Texas, which consisted of 2,078 Mboe of proved developed reserves, and 1,736 MBoe of proved undeveloped reserves. During 2018, the Company’s sales of reserves were located in Maverick County, Texas. Standardized Measure of Future Net Cash Flow The Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Natural Gas Reserves (“Standardized Measure”) does not purport, nor should it be interpreted, to present the fair value of a company’s proved oil and natural gas reserves. Fair value would require, among other things, consideration of expected future economic and operating conditions, a discount factor more representative of the time value of money, and risks inherent in reserve estimates. Under the Standardized Measure, future cash inflows are based upon the forecasted future production of year-end proved reserves which are based on SEC-defined pricing as discussed further below. Future cash inflows are then reduced by estimated future production and development costs to determine net pre-tax cash flow. Future income taxes are computed by applying the statutory tax rate to the excess of pre-tax cash flow over our tax basis in the associated oil and gas properties. Tax credits and permanent differences are also considered in the future income tax calculation. The Company calculates the projected income tax effect using the “year- by-year” method for purposes of the supplemental oil and gas disclosures. Future net cash flow after income taxes is discounted using a 10% annual discount rate to arrive at the Standardized Measure. The following summary sets forth our Standardized Measure (in thousands): December 31, 2019 2018 Cash inflows $ 4,148,426 $ 4,733,751 Production costs (1,348,892) (1,318,059) Development costs (1,231,467) (1,143,083) Income tax expense (183,680) (343,068) Net cash flow 1,384,387 1,929,541 10% annual discount rate (709,288) (976,916) Standardized measure of discounted future net cash flow $ 675,099 $ 952,625 The following are the principal sources of change in the Standardized Measure (in thousands): Year ended December 31, 2019 2018 Standardized Measure, beginning of year $ 952,625 $ 366,747 Sales, net of production costs (141,329) (113,073) Net change in sales prices, net of production costs (422,811) 201,784 Extensions and discoveries, net of future production and development costs 258,433 206,179 Changes in future development costs 283,154 63,297 Previously estimated development costs incurred during the period 84,739 94,673 Revision of quantity estimates (308,312) (198,956) Accretion of discount 110,985 38,124 Change in income taxes 79,728 (142,730) Purchases of reserves in-place — 525,547 Sales of reserves in-place (47,059) (220) Change in production rates and other (175,054) (88,747) Standardized Measure, end of year $ 675,099 $ 952,625 Impact of Pricing The estimates of cash flows and reserve quantities shown above are based upon the unweighted average first-day-of-the-month prices for the previous twelve months, The following average prices were used in determining the Standardized Measure: Year ended December 31, 2019 2018 Oil (per Bbl) $ 56.05 $ 66.34 Gas (per Mcf) $ 2.75 $ 3.50 NGL (per Bbl) $ 16.35 $ 28.15 |
QUARTERLY FINANCIAL DATA (UNAUD
QUARTERLY FINANCIAL DATA (UNAUDITED) | 12 Months Ended |
Dec. 31, 2019 | |
QUARTERLY FINANCIAL DATA (UNAUDITED) | |
QUARTERLY FINANCIAL DATA (UNAUDITED) | NOTE 17—QUARTERLY FINANCIAL DATA (UNAUDITED) The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018 (in thousands, except per share data): Three Months Ended March 31, 2019 June 30, 2019 September 30, 2019 December 31, 2019 Revenues $ 47,740 $ 52,901 $ 51,097 $ 51,842 Income (loss) from operations $ (31,804) $ 13,572 $ 24,126 $ (11,944) Net income (loss) $ (37,209) $ 2,643 $ 13,297 $ (18,321) Income (loss) per share - basic $ (5.41) $ 0.38 $ 1.93 $ (2.67) Income (loss) per share - diluted $ (5.41) $ 0.38 $ 1.93 $ (2.67) Three Months Ended March 31, 2018 June 30, 2018 September 30, 2018 December 31, 2018 Revenues $ 24,036 $ 28,737 $ 53,824 $ 58,336 Income (loss) from operations $ (9,738) $ (47,852) $ (13,202) $ 83,609 Net income (loss) $ (25,731) $ (49,673) $ (20,249) $ 72,720 Income (loss) per share - basic $ (19.75) $ (8.63) $ (2.95) $ 10.58 Income (loss) per share - diluted $ (19.75) $ (8.63) $ (2.95) $ 10.58 (1) Per share amounts have been retroactively adjusted for periods prior to the fourth quarter of 2019 to reflect the Company’s one-for-100 reverse stock split in November 2019, as described in Note 13 to these consolidated financial statements. |
BASIS OF PRESENTATION AND SUM_2
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2019 | |
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |
Basis of Preparation | Basis of Preparation Prior to the Redomiciliation, SEAL reported its consolidated financial statements in accordance with International Financial Reporting Standards (“IFRS”). Following the Redomiciliation, the Company retroactively transitioned to accounting principles generally accepted in the United States of America (“GAAP”) and applied GAAP retrospectively for all prior periods presented. The Company’s consolidated financial statements have been prepared in accordance with GAAP and Securities and Exchange Commission (“SEC”) rules and regulations, and include the accounts of the Company and its consolidated subsidiaries. All intercompany balances and transactions have been eliminated in consolidation. |
Going Concern | Going Concern The accompanying consolidated financial statements are prepared in accordance with GAAP applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. In March 2020, the prevailing market price for oil prices decreased from an average of approximately $60 per barrel for December 2019 to less than $20 per barrel. As described in Note 7, the Company is required to meet certain financial and non-financial covenants as a condition to its credit facilities. Under the Company’s second lien term loan (“Term Loan”), the Company is required to maintain an Asset Coverage Ratio of not less than 1.5 to 1.0, which is calculated as the value of its Total Proved Reserves (PV 9%) based upon the forward month prices quoted on the NYMEX, adjusted for basis differentials or premiums and transportation costs and to reflect the Company’s commodity hedging agreements then in effect to Total Debt. The value of the Company’s oil and gas reserves, (including “Total Proved Reserves” as described in the Term Loan agreement) is highly sensitive to future commodity prices. The Company regularly enters into commodity derivative contracts to protect the cash flows associated with the Company’s proved developed producing wells and to provide supplemental liquidity to mitigate decreases in revenue due to reductions in commodity prices. Based on the Company’s historical experience, in periods of sustained low commodity prices, the prevailing market price for oil and gas services has also decreased, including the types of costs included in the Company’s lease operating expenses, drilling costs, completion costs and costs to equip its wells. Subsequent to December 31, 2019, the Company renegotiated pricing with a number of its vendors and entered into contractual arrangements with drilling and completion service providers at reduced costs relative to the assumed costs in the Company’s year-end reserve report. Additionally, the Company has changed its field operating procedures in response to the material drop in oil prices which further reduces its cost structure relative to that assumed in the Company’s year-end reserve report. The Company continues to work to secure additional costs reductions. Commodity hedging that the Company currently has in place, combined with cost reductions are expected to reduce the impact of recent commodity price declines. However, given the recent decline and continued volatility of commodity prices, the Company cannot assert that it is probable that it will comply with the Asset Coverage Ratio and other covenants within the next 12 months following the date of this report. A breach of any covenant in Company’s credit agreements will result in default under both the Company’s Term Loan and cross default on the Company’s revolving credit facility, after any applicable grace period, which could result in acceleration of the amounts outstanding under the credit facilities by the Company’s lenders. Additionally, the Company’s credit facilities contain the requirement to deliver audited consolidated financial statements without a going concern or like qualification or exception. The issuance of these consolidated financial statements with the accompanying audit opinion constitutes a default under the senior secured revolving credit facility (“Revolving Facility”) and Term Loan. The Company obtained waivers from its Revolving Facility and Term Loan lenders, executed on May 8, 2020 and May 11, 2020, respectively, to waive the event of default arising from the inclusion of the going concern explanatory paragraph included in the audit report for the year ended December 31, 2019 and other related defaults Although the Company has obtained these waivers, there is no guarantee that its lenders will agree to waive events of default or potential events of default in the future. In the event that some or all of the amounts outstanding under its credit facilities are accelerated and become immediately due and payable, the Company does not have sufficient liquidity to repay such outstanding amounts. These conditions and events raise substantial doubt about the entity’s ability to continue as a going concern within one year after the date that the financial statements are issued. Management is currently pursuing and evaluating several plans to mitigate the conditions or events that raise substantial doubt about the entity’s ability to continue as a going concern, which include the following: · Renegotiating pricing with a number of its operating expenditure vendors and has realized lower drilling and completion costs on recent development relative to the costs incurred in 2019 and the assumed costs in the Company’s year-end reserve report. · Negotiating with its lenders to obtain waivers for potential failures in covenants. · Pursuing further changes to its cost structure in response to the material drop in oil prices. · Pursuing additional costs savings with its vendors and other internal costs, including a reduction in force, which occurred in early May 2020. There can be no assurance that sufficient liquidity can be obtained to meet the outstanding obligations of the Company, if repayment of its credit facilities is accelerated. As a result, and given the recent declines and continued volatility in commodity prices, the Company has concluded that management’s plans do not alleviate substantial doubt about the Company’s ability to continue as a going concern. The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty. |
Use of Estimates | Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Items subject to such estimates and assumptions include (i) oil and natural gas reserves; (ii) impairment tests of long-lived assets; (iii) depreciation, depletion and amortization; (iv) asset retirement obligations; (v) assignment of fair value and allocation of purchase price in connection with business combinations; (vi) income taxes; (vii) accrued liabilities; (viii) valuation of derivative instruments; and (ix) accrued revenue and related receivables. Although management believes these estimates are reasonable, actual results could differ from these estimates. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant negative impact to the Company’s business, financial condition, results of operations and cash flows. |
Cash and Cash Equivalents | Cash and Cash Equivalents Cash and cash equivalents consist of demand deposits and highly liquid investments which have an original maturity of three months or less. |
Accounts Receivable Trade and Other | Accounts Receivable Trade and Other The Company has letters of credit in place with certain of its purchasers, which the Company could draw upon in the event the purchaser defaults. Generally, the Company’s oil and gas receivables are collected within two months, and to date, the Company has had minimal bad debts. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. The Company routinely assesses the recoverability of all material trade and other receivables to determine their collectability. At December 31, 2019 and 2018, the Company had no allowance for doubtful accounts. At December 31, 2019 and 2018 the accounts receivable trade and other included the following (in thousands): December 31, 2019 2018 Oil, natural gas and NGL sales $ 18,211 $ 16,408 Joint interest owners 260 584 Commodity hedge contract receivables and other 4,342 4,257 Receivable due from buyer (Dimmit County oil and gas properties) 4,207 — Total accounts receivable trade and other $ 27,020 $ 21,249 |
Concentration of Credit Risk | Concentration of Credit Risk The Company is exposed to credit risk in the event of nonpayment by counterparties, a significant portion of which are concentrated in energy related industries. The creditworthiness of customers and other counterparties is subject to continuing review. As of December 31, 2019, the Company had a receivable from one purchaser, a large midstream company and production purchaser, of $13.2 million that accounted for 73% of total accounts receivable for oil, natural gas and NGL sales. As of December 31, 2019, the Company has a long-term contract in place with this customer, under which the Company is subject to minimum revenue commitments for gathering, processing, transportation and marketing services totaling $54.3 million through 2022. As of December 31, 2018, the Company had a receivable due from the same customer of $12.1 million that accounted for 74% of total accounts receivable for oil, natural gas and NGL sales. The following tables present the percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales for the years ended December 31, 2019 and 2018: Year Ended December 31, 2019 Purchaser A Purchaser B Year Ended December 31, 2018 Purchaser A Purchaser B Purchaser C The Company owns nearly 100% of the working interest in the majority of the wells that it operates; therefore, joint interest billing receivables, and the related credit risk, is minimal. Further, if payment is not made by a working interest partner, the Company can withhold future payments of revenue to that working interest partner. |
Oil and Gas Properties | Oil and Gas Properties Proved. The Company follows the successful efforts method of accounting for its oil and gas properties. Under this method of accounting, all property acquisition costs and development costs are capitalized when incurred and depleted on a unit-of-production basis over the remaining life of proved reserves and proved developed reserves, respectively. Costs of drilling exploratory wells are initially capitalized but are charged to expense if the well is determined to be unsuccessful. For the years ended December 31, 2019 and 2018, the Company recorded depletion, depreciation and amortization expense related to proved oil and gas properties of $91.4 million and $62.1 million, respectively. The Company assesses its proved oil and gas properties for impairment whenever events or circumstances indicate that the carrying value of the assets may not be recoverable. The impairment test compares undiscounted future net cash flows of the assets to the assets’ net book value. If the net book value exceeds future net cash flows, then the cost of the property is written down to fair value. Fair value for oil and gas properties is generally determined based on discounted future net cash flows. There was no impairment expense during the years ended December 31, 2019 or 2018. Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized in income. Gains or losses from the disposal of complete units of depreciable property are recognized in results of operations. For significant projects, interest is capitalized as part of the historical cost of developing and constructing assets. Interest is capitalized until the asset is ready for service. Unproved. Unproved properties consist of costs to acquire undeveloped leases as well as purchases of unproved reserves. Capitalized costs of unproved property are transferred to proved property when related proved reserves are determined and depleted on a unit-of-production basis. The Company evaluates significant unproved properties for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or future plans to develop acreage. There was no unproved property impairment expense during the years ended December 31, 2019 and 2018. Exploratory. Geological and geophysical costs, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage, are expensed as incurred. Costs of seismic studies that are utilized in development drilling within an area of proved reserves are capitalized as development costs. Amounts of seismic costs capitalized are based on only those blocks of data used in determining developmental well locations. To the extent that a seismic project covers areas of both developmental and exploratory drilling, those seismic costs are proportionately allocated between development costs and exploration expense. Costs of drilling exploratory wells are initially capitalized, pending determination of whether the well has found proved reserves. If an exploratory well has not found proved reserves, the costs of drilling the well and other associated costs are charged to expense. Costs incurred for exploratory wells that find reserves, which cannot yet be classified as proved, continue to be capitalized if (i) the well has found a sufficient quantity of reserves to justify completion as a producing well, and (ii) the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. If either condition is not met, or if the Company obtains information that raises substantial doubt about the economic or operational viability of the project, the exploratory well costs, net of any salvage value, are expensed. |
Other Property and Equipment | Other Property and Equipment Other property and equipment consists of office furniture, computer equipment, software and vehicles, which are stated at cost and depreciated using the straight-line method over their estimated useful lives ranging from 3 to 20 years. Leasehold improvements are depreciated over the shorter of the lease term or the estimated useful life of the improvement. Costs that do not extend the useful lives of property and equipment are charged to expense as incurred. Major replacements, renewals and betterments are capitalized. |
Other Current Assets | Other Current Assets Other current assets consist of oil and equipment inventory and prepaid expenses. The Company records oil and equipment inventory at the lower of cost or net realizable value. Prepaid expenses are recorded at cost. |
Assets Held for Sale | Assets Held for Sale Oil and gas properties expected to be sold or otherwise disposed of within one year are classified as assets held for sale and included as current assets in the consolidated balance sheets are separately presented in the accompanying consolidated balance sheets at the lower of carrying value or fair value less estimated costs to sell (“FVLCS”). The Company continued to extract oil and gas from the assets while held for sale, although in accordance with accounting standards, it did not record DD&A for assets classified as held for sale. |
Debt Issuance Costs | Debt Issuance Costs Debt issuance costs related to the Company’s Term Loan are included as a deduction from the carrying amount of the credit facility in the consolidated balance sheets and are amortized to interest expense using the effective interest method over the term of the related debt. Debt issuance costs related to the Revolving Facility are included in other long-term assets and are amortized to interest expense on a straight-line basis over the term of the facility. |
Derivative Instruments | Derivative Instruments The Company enters into derivative contracts, primarily swaps, and costless collars, to manage its exposure to commodity price risk, and follows Financial Accounting Standards Board (“FASB”) ASC Topic 815, Derivatives and Hedging, to account for its derivative financial instruments. The Company also has interest rate swaps contracts to mitigate its exposure to the floating interest rate charged on its long-term debt. In addition, the Company historically entered into foreign exchange derivatives to protect cash flows generated during a common stock equity raise in 2018 from changes in currency fluctuations. Prior to the Company’s redomiciliation, the majority of its common stock issuances were denominated in Australian dollars. All derivative instruments, other than those that meet the “normal purchase normal sale” exclusion, are recorded on the balance sheet as either an asset or liability measured at fair value. Gains and losses from changes in the fair value of derivative instruments are recognized immediately in operations. The Company does not apply hedge accounting to any of its outstanding derivative instruments and, as a result, changes in derivative fair values are recognized as an unrealized gain or loss in operations. Cash flows from derivatives used to manage commodity price risk and interest rate risk are classified in operating activities along with the cash flows of the underlying hedged transactions. Cash flows from derivatives used to manage foreign currency risk are classified in financing activities. The Company does not enter into derivative instruments for speculative or trading purposes. Refer to the Note 10 and Note 11 for further information. |
Asset Retirement and Environmental Obligations | Asset Retirement and Environmental Obligations Asset retirement obligations relate to future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and returning such land to its original condition as specified by the lease or regulatory agencies. The Company follows FASB ASC Topic 410, Asset Retirement and Environmental Obligations , to determine its asset retirement obligation amounts by calculating the present value of the estimated future cash outflows associated with its plug and abandonment obligations. The fair value of a liability for an asset retirement obligation is recorded in the period in which it is incurred (typically when a well is spud or acquired), and the cost of such liability increases the carrying amount of the related long-lived asset by the same amount. The liability is accreted each period through charges to depreciation, depletion and amortization expense, and the capitalized cost is depleted on a unit-of-production basis over the proved developed reserves of the related asset. Revisions typically occur due to changes in estimated abandonment costs or well economic lives, or if federal or state regulators enact new requirements regarding the abandonment of wells, and such revisions result in adjustments to the related capitalized asset and corresponding liability. |
Revenue Recognition | Revenue Recognition The Company recognizes revenue from the sale of oil, natural gas and NGLs in the period that the performance obligations are satisfied. The Company’s performance obligations are primarily comprised of the delivery of oil, natural gas or NGLs at a delivery point. Each barrel of oil, MMBtu of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated. Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer through delivery of oil, natural gas and NGLs, which differs depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of gathering, processing, transportation, and other post-production expenses (“fees and other deductions”) within the accompanying statements of operations, and requires significant judgements. Fees and other deductions incurred prior to control transfer are recorded within the gathering, processing and transportation expense line item on the accompanying statements of operations, while fees and other deductions incurred subsequent to control transfer are recorded as a reduction of oil, gas, and NGLs production revenue. The Company has three types of contracts under which oil, gas, and NGLs production revenue is generated, which are summarized below: 1) The Company sells oil production at or near the wellhead and receives an agreed-upon index price from the purchaser, net of basis, quality, and transportation differentials. Under this arrangement, control transfers at or near the wellhead. 2) The Company sells unprocessed natural gas to a midstream processor at the wellhead or inlet of the midstream processing facility. The midstream processor gathers and processes the raw natural gas stream and remits proceeds to the Company from the ultimate sale of the processed NGLs and residue natural gas to third parties. In such arrangements, the midstream processor obtains control of the product at the wellhead or inlet of the facility and is considered the customer. Proceeds received for unprocessed natural gas under these arrangements are reflected as natural gas or NGL revenue and are recorded net of transportation and processing fees incurred by the midstream processor after control has transferred. 3) The Company has certain processing arrangements that include the delivery of unprocessed natural gas to the inlet of a midstream processor’s facility for processing. Upon completion of processing, the midstream processor purchases the NGLs and redelivers residue gas back to the Company in-kind. For the NGLs, control is deemed to have transferred after it has been separated from the residue gas. The midstream processor remits payment to the Company based on the proceeds it generates from selling the NGLs to other third parties. The Company recognizes the proceeds as NGL revenue. For the residue gas taken in-kind, the Company has separate sales contracts where control transfers at points downstream of the processing facility. The Company recognizes proceeds from the downstream contracts as natural gas revenue. Under these processing arrangements for both NGL and natural gas, the Company recognizes gathering, transportation, and processing fees incurred prior to control transfer as expense recorded within the gathering, processing and transportation expense line item on the accompanying consolidated statements of operations. Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements from the purchasers of hydrocarbons and the related cash consideration are received within two months after production has occurred. As a result, the Company must estimate the amount of production delivered to the customer and the consideration that will ultimately be received for sale of the product. To estimate accounts receivable from contracts with customers, the Company uses knowledge of its properties, metered sales volumes, historical performance, contractual arrangements, index pricing, quality and transportation differentials, and other factors as the basis for these estimates. Variances between estimates and the actual amounts received are recorded in the month payment is received, but have not historically been material. Estimated revenue due to the Company is recorded within accounts receivable trade and other on the accompanying consolidated balance sheets until payment is received. The accounts receivable balance from contracts with customers within the accompanying balance sheet as of December 31, 2019 and 2018 was $18.2 million and $16.4 million, respectively. |
Stock-Based Compensation | Stock-Based Compensation Equity - Settled Compensation Prior to the effectiveness of the Redomiciliation, SEAL issued restricted share units (“RSUs”) pursuant to its Long Term Incentive Plan (the “Plan”) to motivate management and employees to make decisions benefiting long-term value creation, retain management and employees and reward the achievement of the Company’s long-term goals. The RSUs are generally settled based on the achievement of certain goals established by the Compensation Committee and approved by the Board. There were three types of RSU awards: 1) Time based vesting: The fair value of time-based RSUs is determined based on the price of the underlying equity on the date of grant and the expense is recognized over the vesting period. 2) Total shareholder return (“TSR”) or absolute total share-holder return (“ATSR”): Certain RSUs vest based on the achievement of metrics related to the a three‑year ATSR or TSR as compared to a peer group or a market index. A Monte Carlo simulation model to determine the fair value of such RSUs and the expense is recognized over the vesting period. The Monte Carlo model was used to determine based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. The expected volatility used in the model is based on the historical volatility commensurate with the length of the performance period of the award. The risk-free rate used in the model is based on published interest rates relevant to the term of the RSU award. 3) Performance targets: Certain RSUs vest based on the achievement of Adjusted EBITDAX per debt adjusted share or average daily production volume per debt adjusted share metrics during 2019 and 2020. At the end of each reporting period, the amount of expense recorded is adjusted based on the number of shares it ultimately expects to vest based on the comparison of internal forecasts to the performance conditions. The fair value of the equity to which employees become entitled is measured at grant date and recognized as an expense over the vesting period with a corresponding increase in equity. The Company accounts for forfeitures of RSUs as they occur. See Note 13 for further discussion of the RSUs. |
Defined Contribution Plan | Defined Contribution Plan The Company has a defined contribution retirement plan for all employees. The plan is funded by employee contributions and discretionary Company contributions. The Company’s contributions for the years ended December 31, 2019 and 2018 were $0.6 million and $0.3 million, respectively. |
Income Taxes | Income Taxes Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are accounted for using the liability method. Under this method, deferred tax assets and liabilities are determined by applying the enacted statutory tax rates in effect at the end of a reporting period to the cumulative temporary differences between the tax bases of assets and liabilities and their reported amounts in the Company’s consolidated financial statements. The effect on deferred taxes for a change in tax rates is recognized in income in the period that includes the enactment date. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized. The Company’s uncertain tax positions must meet a more-likely-than-not realization threshold to be recognized, and any potential accrued interest and penalties related to unrecognized tax benefits are recognized within income tax expense (benefit). |
Earnings (Loss) Per Share | Earnings (Loss) Per Share Basic earnings (loss) per common share is calculated by dividing net income (loss) by the weighted average number of common shares outstanding during each period. Diluted earnings per common share is calculated by dividing net income by the weighted average number of diluted common shares outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted earnings per share calculations consist of outstanding restricted share units which have been issued to employees, all using the treasury stock method. When a loss from continuing operations exists, all dilutive securities and potentially dilutive securities are anti-dilutive and are therefore excluded from the computation of diluted earnings per share. |
Industry Segment and Geographic Information | Industry Segment and Geographic Information The Company’s strategic focus is the exploration, development and production of large, repeatable onshore resource plays in North America. All of the Company’s operations and assets are located in the Eagle Ford area of south Texas. Management has determined, based upon the reports the Chief Operating Decision Maker (the Company’s Chief Executive Officer) reviews and uses to make strategic decisions, that the Company has one reportable segment being oil and natural gas development and production in North America. |
Foreign Currency Transaction Gains and Losses | Foreign Currency Transaction Gains and Losses The U.S. dollar is the functional currency for the Company. The Company’s Australian subsidiaries have an Australian dollar functional currency, and asset and liability accounts denominated in foreign currencies are remeasured to their U.S. dollar equivalent at the exchange rate in effect at the end of each reporting period. Foreign currency gains and losses arising from translation are reflected in accumulated other comprehensive (loss) in the consolidated balance sheets. |
Business Combinations | Business Combinations A business combination is a transaction in which an acquirer obtains control of one or more businesses. The Company accounts for business combinations using the acquisition method of accounting, under which the cost of the acquisition is allocated to assets acquired and liabilities assumed based upon their respective fair values as of the acquisition date. Costs directly attributable to the business combination are expensed as incurred, except those directly and incrementally attributable to equity issuance. |
Recently Issued and Adopted Accounting Standards | Recently Issued and Adopted Accounting Standards In February 2016, the FASB issued Accounting Standards Update (“ASU”) 2016-02, Leases (“ASU 2016-02”). The FASB subsequently issued various ASUs which provided additional implementation guidance, and these ASUs collectively make up FASB ASC Topic 842 – Leases (“ASC 842”). The objective of ASC 842 is to increase transparency and comparability among organizations, by recognizing lease liabilities and right-of-use assets on the balance sheet at the date of initial application and disclosing key information about leasing arrangements. The Company adopted ASC 842 using the modified retrospective method effective January 1, 2019. Accordingly, the 2019 financial statements are not comparable with respect to leases in effect for all periods prior to January 1, 2019. Refer to Note 6 for further information on the Company’s implementation of this standard. In June 2016, the FASB issued ASU 2016-13, Financial Instruments – Credit Losses (Topic 326) Measurement of Credit Losses on Financial Instruments, which provides a model, known as the current expected credit loss model (“CECL model”), to estimate the expected lifetime credit loss on financial assets, including trade and other receivables. The Company adopted the ASU effective January 1, 2020, and it did not have a material impact on the Company’s consolidated financial statements as the Company does not have a history of material credit losses. |
BASIS OF PRESENTATION AND SUM_3
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |
Schedule of accounts receivable trade and other | December 31, 2019 2018 Oil, natural gas and NGL sales $ 18,211 $ 16,408 Joint interest owners 260 584 Commodity hedge contract receivables and other 4,342 4,257 Receivable due from buyer (Dimmit County oil and gas properties) 4,207 — Total accounts receivable trade and other $ 27,020 $ 21,249 |
Schedule of percentages by purchaser that accounted for 10% or more of the Company’s total oil, NGL and natural gas sales | Year Ended December 31, 2019 Purchaser A Purchaser B Year Ended December 31, 2018 Purchaser A Purchaser B Purchaser C |
OIL AND GAS PROPERTIES (Tables)
OIL AND GAS PROPERTIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
OIL AND GAS PROPERTIES. | |
Schedule of oil and gas producing activities | December 31, 2019 2018 Oil and gas properties, successful efforts method: Unproved $ 25,037 $ 48,049 Proved 1,090,774 925,551 Work in progress 7,097 12,948 1,122,908 986,548 Accumulated depletion, depreciation and amortization (379,961) (293,598) Oil and gas properties, net $ 742,947 $ 692,950 |
ACQUISITIONS AND DISPOSITIONS (
ACQUISITIONS AND DISPOSITIONS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
Business Acquisition [Line Items] | |
Schedule of fair value of the assets acquired and the liabilities assumed | The following table reflects the fair value of the assets acquired and the liabilities assumed (in thousands): Assets Acquired: December 31, 2018 Oil and gas properties Proved $ 173,750 Unproved 43,642 Liabilities Assumed: Trade and other payables (80) Asset retirement obligation (1,522) Net assets acquired $ 215,790 |
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC | |
Business Acquisition [Line Items] | |
Schedule of revenues and direct operating expenses, including depletion, depreciation and amortization expense from acquired properties. | Revenues $ 64,507 Direct operating expenses (1) (45,194) Income from operations $ 19,313 (1) Direct operating expenses include lease operating and workover expense, gathering, processing and transportation expense, production taxes and depreciation, depletion and amortization expense. |
ASSETS HELD FOR SALE (Tables)
ASSETS HELD FOR SALE (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
ASSETS HELD FOR SALE. | |
Schedule of assets held for sale | The consolidated balance sheet includes assets and liabilities related to assets held for sale, comprised of the following as of December 31, 2018 (in thousands): Assets held for sale: December 31, 2018 Oil and gas properties - Dimmit County, Texas $ 23,471 Liabilities related to assets held for sale: Asset retirement obligations (193) Net assets held for sale $ 23,278 |
ACCRUED LIABILITIES (Tables)
ACCRUED LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
ACCRUED LIABILITIES | |
Summary of accrued liabilities | The following is a summary of accrued liabilities as of December 31, 2019 and 2018 (in thousands): December 31, 2019 2018 Oil and natural gas properties: Capital expenditures $ 4,168 $ 12,879 Re-fracture liability 764 900 Lease operating and workover expenses and other 7,393 6,586 Accrued interest payable 6,885 458 General and administrative expense 6,894 4,462 Finance lease liabilities 305 — Total accrued liabilities $ 26,409 $ 25,285 |
LEASES (Tables)
LEASES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
LEASES | |
Schedule of classification of lease assets and liabilities | Right-of-use assets Balance Sheet Location December 31, 2019 Operating lease right-of-use assets Operating lease right-of-use assets $ 17,331 Finance lease right-of-use assets Other property and equipment, net of accumulated depreciation 747 Total right-of-use assets $ 18,078 Lease liabilities Balance Sheet Location December 31, 2019 Operating lease liabilities - current Operating lease liabilities - current $ 7,720 Operating lease liabilities - non-current Operating lease liabilities - non-current 9,611 Finance lease liabilities - current Accrued expenses Finance lease liabilities - non-current Other long-term liabilities Total lease liabilities $ 18,065 |
Schedule of lease terms and discount rates | Weighted Average Remaining Lease Term (years) Operating Leases 5.22 Finance Leases 2.58 Weighted Average Discount Rate Operating Leases Finance Leases |
Schedule of total lease cost | Weighted Average Remaining Lease Term (years) Operating Leases 5.22 Finance Leases 2.58 Weighted Average Discount Rate Operating Leases Finance Leases The following summarizes total lease cost, which includes amounts recognized on the consolidated statement of operations and other comprehensive income (loss) and amounts capitalized related to the Company’s leases (in thousands): Year ended December 31, 2019 Operating lease cost (1) $ 11,729 Finance lease cost: Amortization of right-of-use assets $ 187 Interest on lease liabilities 20 Total finance lease cost $ 207 Short-term lease cost $ 1,065 Variable lease cost $ 1,395 Sublease income $ 150 (1) Operating lease cost of $6.3 million related to the Company’s drilling rig was capitalized to oil and gas properties on the consolidated balance sheet and will be depleted in accordance with the Company’s policies. |
Schedule of supplemental cash flow information related to the Company’s leases | December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities Operating cash flows from operating leases $ 5,271 Operating cash flows from finance leases $ 20 Investing cash flows from operating leases $ 6,308 Financing cash flows from finance leases $ 187 Supplemental non-cash information on lease liabilities arising from right of use assets Operating lease liability additions $ 17,358 Finance lease liability additions $ 640 |
Schedule of operating lease obligations | Year Ending December 31, Operating Leases Finance Leases 2020 $ 7,848 $ 312 2021 4,061 305 2022 2,819 150 2023 2,192 12 2024 845 - Thereafter 1,481 - Total lease payments $ 19,246 $ 779 Less: Interest (1,915) (45) Total discounted lease payments $ 17,331 $ 734 |
Schedule of finance lease obligations | Year Ending December 31, Operating Leases Finance Leases 2020 $ 7,848 $ 312 2021 4,061 305 2022 2,819 150 2023 2,192 12 2024 845 - Thereafter 1,481 - Total lease payments $ 19,246 $ 779 Less: Interest (1,915) (45) Total discounted lease payments $ 17,331 $ 734 |
Schedule of future minimum contractual payments for operating leases under the scope of ASC 840 | Year Ending December 31, Drilling Rig Operating Leases Capital Leases 2019 $ 4,106 $ 2,087 $ 97 2020 - 1,376 98 2021 - 602 90 2022 - 141 15 2023 - 83 12 Thereafter - 964 - Total lease payments $ 4,106 $ 5,253 $ 312 Less interest (26) Total discounted lease payments $ 286 |
Schedule of future minimum contractual payments for capital leases under the scope of ASC 840 | Year Ending December 31, Drilling Rig Operating Leases Capital Leases 2019 $ 4,106 $ 2,087 $ 97 2020 - 1,376 98 2021 - 602 90 2022 - 141 15 2023 - 83 12 Thereafter - 964 - Total lease payments $ 4,106 $ 5,253 $ 312 Less interest (26) Total discounted lease payments $ 286 |
LONG-TERM DEBT (Tables)
LONG-TERM DEBT (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
LONG-TERM DEBT | |
Summary of long-term debt | The following is a summary of long-term debt as of December 31, 2019 and 2018 (in thousands): December 31, 2019 2018 Revolving Facility $ 115,000 $ 65,000 Term Loan 250,000 250,000 Total long-term debt 365,000 315,000 Deferred financing fees, net of accumulated amortization (11,510) (14,196) Total credit facilities, net of deferred financing fees $ 353,490 $ 300,804 |
ASSET RETIREMENT OBLIGATIONS (T
ASSET RETIREMENT OBLIGATIONS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
ASSET RETIREMENT OBLIGATIONS | |
Schedule of reconciliation of the Company’s asset retirement obligations | The following table provides a reconciliation of the Company’s asset retirement obligations for the years ended December 31, 2019 and 2018 (in thousands): December 31, 2019 2018 Balance, beginning of year $ 3,489 $ 1,549 Additional liability incurred 145 195 Obligations settled (85) (29) Obligations on assets acquired — 1,522 Obligations on assets sold (232) — Accretion expense 336 252 Balance, end of year $ 3,653 $ 3,489 Liabilities related to assets held for sale $ — $ 193 Long-term 3,653 3,296 $ 3,653 $ 3,489 |
INCOME TAXES (Tables)
INCOME TAXES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
INCOME TAXES | |
Schedule of components of the provision for income taxes | Year Ended December 31, 2019 2018 Current income tax expense - Federal $ — $ 2,301 Deferred income tax expense (benefit) Federal (8,281) (5,555) State 11 318 Foreign (503) (2,929) Total deferred income tax expense (benefit) (8,773) (8,166) Valuation Allowance Income tax provision (benefit) 4,255 19,822 Total income tax expense (benefit) $ (4,518) $ 13,957 |
Schedule of reconciliations of the income tax (expense) benefit | Year Ended December 31, 2019 2018 Income tax benefit at the federal statutory rate $ (9,263) $ (1,885) State income taxes - net of federal income tax benefits 10 290 Stock-based compensation 114 839 Nondeductible expenses 519 1,055 Change in valuation allowance 4,255 19,822 Foreign tax rates (166) (877) Australian tax losses on U.S. Restructuring — (3,284) Deemed interest payment due to U.S. restructuring — (4,350) U.S. withholding tax net of foreign tax credit — 2,301 Other 13 46 Total income tax expense (benefit) $ (4,518) $ 13,957 |
Schedule of components of net deferred taxes | December 31, 2019 2018 Deferred tax assets: Net operating loss carryforward $ 76,624 $ 70,560 Business interest carryforward 10,474 7,054 Stock-based compensation 93 102 Statutory depletion carryforward 2,927 2,977 Unrealized (gain) loss on commodity derivative 1,147 (6,453) Lease obligations 3,735 — Property, plant and equipment 82 (122) Other assets 524 1,688 Total deferred tax assets 95,606 75,806 Valuation allowance (64,898) (60,643) Deferred tax assets, net 30,708 15,163 Deferred tax liabilities: Basis of oil and gas properties (33,950) (26,819) Lease assets (3,896) — Total deferred tax liabilities (37,846) (26,819) Deferred tax liabilities, net $ (7,138) $ (11,656) |
DERIVATIVE FINANCIAL INSTRUME_2
DERIVATIVE FINANCIAL INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
DERIVATIVE FINANCIAL INSTRUMENTS | |
Summary of commodity derivative positions | Oil Swaps - WTI (1) Year Volumes (Bbl) Weighted Average Price per Bbl 2020 $ 57.17 2021 $ 54.84 Oil Collars - WTI Year Volumes (Bbl) Weighted Average Price per Bbl - Floor Weighted Average Price per Bbl - Ceiling 2020 $ 54.47 $ 61.82 2021 $ 45.00 $ 65.00 2022 $ 40.00 $ 66.00 2023 $ 40.00 $ 63.10 Oil Three-Way Collars - WTI Year Volumes (Bbl) Weighted Average Price per Bbl - Floor Sold Weighted Average Price per Bbl - Floor Purchased Weighted Average Price per Bbl - Ceiling 2020 $ 35.00 $ 50.00 $ 59.60 2021 $ 35.00 $ 50.00 $ 57.50 2022 $ 35.00 $ 50.00 $ 56.90 Propane Calls Sold - OPIS Propane Mont Belvieu - TET (2) Year Volumes (Bbl) Weighted Average Price per Bbl 2020 $ 0.70 Oil Basis Swaps - WTI-HOU (3) Year Volumes (Bbl) Weighted Average Differential per Bbl 2020 $ 2.98 2021 $ 2.53 Natural Gas Swaps Price Swaps - HH (4) Price Swaps - HSC (5) Year Volumes (MMBtu) Weighted Average Price per MMBtu Volumes (MMBtu) Weighted Average Price per MMBtu 2020 $ 2.70 $ 2.53 2021 $ 2.69 $ 2.50 2022 $ 2.76 $ 2.54 2023 $ 2.64 Natural Gas Collars - HH Year Volumes (MMBtu) Weighted Average Price per MMBtu - Floor Weighted Average Price per MMBtu - Ceiling 2020 $ 2.50 $ 2.95 HSC Year Volumes (MMBtu) Weighted Average Price per MMBtu - Floor Weighted Average Price per MMBtu - Ceiling 2020 $ 2.60 $ 2.91 Subsequent to December 31, 2019, the Company entered into the following commodity derivative positions: Oil Swaps Price Swaps - WTI Year Volumes (Bbl) Weighted Average Price per Bbl 2020 $ 49.39 2021 $ 48.38 Natural Gas Swaps Price Swaps - HH Year Volumes (MMBtu) Weighted Average Price per MMBtu 2021 $ 2.67 The following is a list of index prices: (1) WTI crude oil as quoted on NYMEX. (2) Mont Belvieu – Texas Eastern Transmission (“TET”) propane as quoted by Oil Price Information Service (“OPIS”). (3) WTI Houston Argus (“WTI-HOU”) crude oil as quoted by Argus US Pipeline. (4) Henry Hub (“HH”) natural gas as quoted on the NYMEX. (5) Houston Ship Channel (“HSC”) natural gas as quoted in Platt’s Inside FERC. |
Summary of interest rate swaps | Interest Rate Derivatives A summary of the Company’s interest rate swaps as of December 31, 2019 follows (notional amount in thousands): Portion of Term Term Loan Effective Date Termination Date Notional Amount Fixed Rate (1) Face Amount July 11, 2019 July 11, 2020 $ 3.016 % 75 % July 11, 2020 July 11, 2021 $ 3.072 % 50 % July 11, 2021 July 11, 2022 $ 3.061 % 50 % July 13, 2022 May 23, 2023 $ 3.042 % 50 % (1) Each contract has a 1% floor, consistent with the structure of the Term Loan. |
Summary of derivative instruments offset in the consolidated balance sheets | The following tables summarize the location and fair value amounts of all the Company’s derivative instruments in the consolidated balance sheets, as well as the gross recognized derivative assets, liabilities and amounts offset in the consolidated balance sheets (in thousands): December 31, 2019 Gross Gross Net Recognized Recognized Amounts Fair Value Not Designated as ASC 815 Hedges Balance Sheet Classification Assets/Liabilities Offset Assets/Liabilities DERIVATIVE ASSETS : Current: Derivative financial instruments — commodity contracts Derivative assets $ 2,863 $ (1,648) $ 1,215 Derivative financial instruments — interest rate swaps Derivative assets 8 (8) — Long-term: Derivative financial instruments — commodity contracts Derivative assets 2,637 (1,759) 878 Derivative financial instruments — interest rate swaps Derivative assets 377 (377) — Total derivative assets 5,885 2,093 DERIVATIVE LIABILITIES : Current: Derivative financial instruments — commodity contracts Derivative liabilities 3,946 (1,648) 2,298 Derivative financial instruments — interest rate swaps Derivative liabilities 2,104 (8) 2,096 Total current derivative liabilities 6,050 4,394 Long-term: Derivative financial instruments — commodity contracts Derivative liabilities 1,761 (1,759) 2 Derivative financial instruments — interest rate swaps Derivative liabilities 4,044 (377) 3,667 Total long-term derivative liabilities 5,805 3,669 Total derivative liabilities 11,855 8,063 $ (5,970) $ (5,970) December 31, 2018 Gross Gross Net Recognized Recognized Amounts Fair Value Not Designated as ASC 815 Hedges Balance Sheet Classification Assets/Liabilities Offset Assets/Liabilities DERIVATIVE ASSETS : Current: Derivative financial instruments — commodity contracts Derivative assets $ 24,877 $ (562) $ 24,315 Derivative financial instruments — interest rate swaps Derivative assets 5,081 (5,081) — Long-term: Derivative financial instruments — commodity contracts Derivative assets 8,403 (400) 8,003 Derivative financial instruments — interest rate swaps Derivative assets 11,142 (11,142) — Total derivative assets 49,503 32,318 DERIVATIVE LIABILITIES : Current: Derivative financial instruments — commodity contracts Derivative liabilities 787 (562) 225 Derivative financial instruments — interest rate swaps Derivative liabilities 5,292 (5,081) 211 Total current derivative liabilities 6,079 436 Long-term: Derivative financial instruments — commodity contracts Derivative liabilities 1,051 (400) 651 Derivative financial instruments — interest rate swaps Derivative liabilities 13,069 (11,142) 1,927 Total long-term derivative liabilities 14,120 2,578 Total derivative liabilities 20,199 3,014 $ 29,304 $ 29,304 |
Summary of derivative instruments in statement of operations | Gain (Loss) Recognized in Income Year Ended December 31, Not designated as ASC 815 Hedges Statement of Operations Classification 2019 2018 Foreign currency Gain on foreign currency derivative financial instruments $ - $ 6,838 Commodity contracts Gain (loss) on commodity derivative financial instruments (20,542) 40,216 Interest rate swap Interest expense (4,270) (2,435) $ (24,812) $ 44,619 |
FAIR VALUE MEASUREMENT (Tables)
FAIR VALUE MEASUREMENT (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
FAIR VALUE MEASUREMENT | |
Schedule of balance sheets grouped into the fair value hierarchy | The financial assets and liabilities measured at fair value on a recurring basis in the consolidated balance sheets are grouped into the fair value hierarchy as follows (in thousands): December 31, 2019 Level 1 Level 2 Level 3 Total Assets measured at fair value Derivative commodity contracts $ — $ 2,093 $ — $ 2,093 Liabilities measured at fair value Derivative commodity contracts — (2,300) — (2,300) Derivative interest rate swaps — (5,763) — (5,763) — (8,063) — (8,063) Net fair value $ — $ (5,970) $ — $ (5,970) December 31, 2018 Level 1 Level 2 Level 3 Total Assets measured at fair value Derivative commodity contracts $ — $ 32,318 $ — $ 32,318 Liabilities measured at fair value Derivative commodity contracts — (876) — (876) Derivative interest rate swaps — (2,138) — (2,138) — (3,014) — (3,014) Net fair value $ — $ 29,304 $ — $ 29,304 |
Schedule of non-recurring fair value measurements | Net Carrying Value as of Fair Value Measurements Using (in thousands) December 31, 2018 Level 1 Level 2 Level 3 Assets held for sale $ 23,471 $ — $ — $ 23,471 |
EARNINGS PER SHARE (Tables)
EARNINGS PER SHARE (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
EARNINGS PER SHARE | |
Schedule of reconciliation between basic and diluted earnings per share | The reconciliations between basic and diluted earnings (loss) per share are as follows (in thousands, except per share data): Year Ended December 31, 2019 2018 Net loss $ (39,590) $ (22,933) Weighted average shares (1): Weighted average common shares outstanding, basic 6,874,170 5,236,524 Diluted effect of incremental shares related to restricted share units (2) — — Weighted average common shares outstanding, diluted 6,874,170 5,236,524 Net loss per share: Basic and diluted $ (5.76) $ (4.38) (1) All share numbers have been retroactively adjusted for the 2019 and 2018 periods to reflect the Company’s one for 100 share consolidation in November 2019, as described in Note 13. For the year ended December 31, 2019, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes anti-dilutive shares of 320 shares of service-based awards. For the year ended December 31, 2018, the Company had a net loss and therefore the diluted earnings per share calculation for that period excludes anti-dilutive shares of 786 shares of service-based awards. |
EQUITY (Tables)
EQUITY (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
EQUITY | |
Schedule of restricted share units | Weighted Average Fair Value at Number of RSUs Grant Date Outstanding at December 31, 2017 33,804 $ 166.87 Granted 71,175 $ 18.80 Vested (6,916) $ 361.03 Forfeited (6,724) $ 198.37 Outstanding at December 31, 2018 91,339 $ 34.37 Granted 38,373 $ 20.31 Vested (1) (1,425) $ 61.56 Forfeited (43,358) $ 51.20 Outstanding at December 31, 2019 84,929 $ 22.97 (1) Includes 375 RSUs that have vested, but will be settled in 2020. |
Schedule of RSUs outstanding | Number of RSUs Grant Date 2019 2018 March 15, 2016 (1) — 4,428 May 27, 2016 (1) — 4,342 June 29, 2016 (1) — 497 February 17, 2017 (1)(2) 3,411 4,572 May 25, 2017 (1)(2) 3,724 3,724 October 23, 2017 (1) 745 745 October 23, 2017 375 750 December 29, 2017 497 1,106 December 26, 2018 (3) 30,414 35,587 December 26, 2018 (4) 15,207 35,588 May 5, 2019 1,775 — May 5, 2019 (1) 5,325 — May 31, 2019 (3) 15,637 — May 31, 2019 (4) 7,819 — Total RSUs outstanding 84,929 91,339 (1) RSUs vest based on three‑year absolute total shareholder return (“ATSR”). (2) ATSR RSUs were evaluated for vesting subsequent to December 31, 2019. The vesting conditions were not met and the outstanding awards will be forfeited in 2020. (3) RSUs vest based on three-year total shareholder return (“TSR”) as compared to the XOP index. (4) Company performance-based RSUs vest based on 2019 and 2020 EBITDA per debt adjusted share and production per debt adjusted share. |
Schedule of restricted share awards vesting conditions | The following tables summarize the RSUs issued and their related grant date, fair value and vesting conditions. RSUs awarded during the year ended December 31, 2019: Fair Value at Grant Date Number of RSUs Grant Date Vesting Conditions May 5, 2019 1,775 $ 29.49 Vests on 3rd anniversary of award May 5, 2019 5,325 $ 16.35 0 % - 200% based on 3 year TSR as compared to the XOP index. May 31, 2019 15,637 $ 16.13 0 % - 200% based on 3 year TSR as compared to the XOP index. May 31, 2019 3,909 $ 24.92 0 % - 200% based on 2019 EBITDA per Debt Adjusted Share May 31, 2019 3,909 $ 24.92 0 % - 200% based on 2020 EBITDA per Debt Adjusted Share May 31, 2019 3,909 $ 24.92 0 % - 200% based on 2019 Production per Debt Adjusted Share May 31, 2019 3,909 $ 24.92 0 % - 200% based on 2020 Production per Debt Adjusted Share 38,373 The following tables summarize the RSUs issued and their related grant date, fair value and vesting conditions. RSUs awarded during the year ended December 31, 2018: Fair Value at Grant Date Number of RSUs Grant Date Vesting Conditions December 26, 2018 35,587 $ 16.44 0 % - 200% based on 3 year TSR as compared to the XOP index December 26, 2018 8,897 $ 21.16 0 % - 200% based on 2019 EBITDA per Debt Adjusted Share December 26, 2018 8,897 $ 21.16 0 % - 200% based on 2020 EBITDA per Debt Adjusted Share December 26, 2018 8,897 $ 21.16 0 % - 200% based on 2019 Production per Debt Adjusted Share December 26, 2018 8,897 $ 21.16 0 % - 200% based on 2020 Production per Debt Adjusted Share 71,175 |
COMMITMENTS AND CONTINGENCIES (
COMMITMENTS AND CONTINGENCIES (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
COMMITMENTS AND CONTINGENCIES | |
Schedule of the commitments that have initial or remaining noncancelable terms in excess of one year | 2020 2021 2022 Total Hydrocarbon gathering and handling agreement $ 14,297 $ 13,972 $ 6,675 $ 34,944 Crude oil and condensate purchase agreements 4,710 7,513 4,317 16,540 Gas processing agreement 2,017 - - 2,017 Gas transportation agreements 783 - - 783 Total MRC $ 21,807 $ 21,485 $ 10,992 $ 54,284 |
SUPPLEMENTAL DISCLOSURES ABOU_2
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | |
Schedule of capitalized cost incurred in oil and gas production, exploration and development activities | The Company’s oil and gas activities for 2019 and 2018 were entirely within the United States. Costs incurred in oil and gas producing activities were as follows (in thousands): Year ended December 31, 2019 2018 Property acquisition costs Proved $ — $ 173,750 Unproved (1) 177 45,252 Exploration costs 335 2,789 Development costs (2) (3) 149,766 181,463 (1) Includes costs incurred related to its Dimmit County assets, which were classified as held for sale during 2018 through their sale in October 2019, of nil and $1.0 million during the years ended December 31, 2019 and 2018, respectively. (2) Development costs include $7.1 million and $12.9 million wells in-progress as of December 31, 2019 and 2018, respectively. These wells in-progress were either drilling, waiting on hydraulic fracturing or production testing. (3) Includes costs incurred related to its Dimmit County assets, which were classified as held for sale during 2018 through their sale in October 2019, of $8.4 million and $5.3 million during the years ended December 31, 2019 and 2018, respectively. |
Schedule of estimated reserved data | Natural Oil Gas NGL Total (MBbl) (MMcf) (MBbl) (MBoe) Proved reserves: January 1, 2018 27,987 59,409 9,190 47,079 Revisions of previous estimates (5,138) (14,257) (3,201) (10,716) Extensions and discoveries 7,577 12,889 2,179 11,904 Purchases of reserves in-place 30,474 55,367 8,801 48,503 Production (2,256) (4,534) (497) (3,508) Sales of reserves in-place (15) (33) - (21) December 31, 2018 58,629 108,841 16,472 93,241 Revisions of previous estimates (14,358) (27,504) (4,225) (23,168) Extensions and discoveries 23,018 52,297 7,915 39,649 Production (3,077) (5,768) (798) (4,836) Sales of reserves in-place (1,424) (6,962) (1,230) (3,814) December 31, 2019 62,788 120,904 18,134 101,072 Proved developed reserves: December 31, 2018 16,742 33,169 4,927 27,197 December 31, 2019 16,101 26,930 4,022 24,611 Proved undeveloped reserves December 31, 2018 41,887 75,672 11,545 66,044 December 31, 2019 46,687 93,974 14,112 76,461 |
Summary of standardized measure | The following summary sets forth our Standardized Measure (in thousands): December 31, 2019 2018 Cash inflows $ 4,148,426 $ 4,733,751 Production costs (1,348,892) (1,318,059) Development costs (1,231,467) (1,143,083) Income tax expense (183,680) (343,068) Net cash flow 1,384,387 1,929,541 10% annual discount rate (709,288) (976,916) Standardized measure of discounted future net cash flow $ 675,099 $ 952,625 |
Schedule of principal source of change in the standardized measure | The following are the principal sources of change in the Standardized Measure (in thousands): Year ended December 31, 2019 2018 Standardized Measure, beginning of year $ 952,625 $ 366,747 Sales, net of production costs (141,329) (113,073) Net change in sales prices, net of production costs (422,811) 201,784 Extensions and discoveries, net of future production and development costs 258,433 206,179 Changes in future development costs 283,154 63,297 Previously estimated development costs incurred during the period 84,739 94,673 Revision of quantity estimates (308,312) (198,956) Accretion of discount 110,985 38,124 Change in income taxes 79,728 (142,730) Purchases of reserves in-place — 525,547 Sales of reserves in-place (47,059) (220) Change in production rates and other (175,054) (88,747) Standardized Measure, end of year $ 675,099 $ 952,625 |
Schedule of average prices used in determining the standardized measure | Year ended December 31, 2019 2018 Oil (per Bbl) $ 56.05 $ 66.34 Gas (per Mcf) $ 2.75 $ 3.50 NGL (per Bbl) $ 16.35 $ 28.15 |
QUARTERLY FINANCIAL DATA (UNA_2
QUARTERLY FINANCIAL DATA (UNAUDITED) (Tables) | 12 Months Ended |
Dec. 31, 2019 | |
QUARTERLY FINANCIAL DATA (UNAUDITED) | |
Summary of the unaudited quarterly financial data | The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018 (in thousands, except per share data): Three Months Ended March 31, 2019 June 30, 2019 September 30, 2019 December 31, 2019 Revenues $ 47,740 $ 52,901 $ 51,097 $ 51,842 Income (loss) from operations $ (31,804) $ 13,572 $ 24,126 $ (11,944) Net income (loss) $ (37,209) $ 2,643 $ 13,297 $ (18,321) Income (loss) per share - basic $ (5.41) $ 0.38 $ 1.93 $ (2.67) Income (loss) per share - diluted $ (5.41) $ 0.38 $ 1.93 $ (2.67) Three Months Ended March 31, 2018 June 30, 2018 September 30, 2018 December 31, 2018 Revenues $ 24,036 $ 28,737 $ 53,824 $ 58,336 Income (loss) from operations $ (9,738) $ (47,852) $ (13,202) $ 83,609 Net income (loss) $ (25,731) $ (49,673) $ (20,249) $ 72,720 Income (loss) per share - basic $ (19.75) $ (8.63) $ (2.95) $ 10.58 Income (loss) per share - diluted $ (19.75) $ (8.63) $ (2.95) $ 10.58 Per share amounts have been retroactively adjusted for periods prior to the fourth quarter of 2019 to reflect the Company’s one-for-100 reverse stock split in November 2019, as described in Note 13 to these consolidated financial statements. |
BASIS OF PRESENTATION AND SUM_4
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Description of Operations and Going Concern (Details) | Apr. 29, 2020 | Nov. 26, 2019shares | Mar. 31, 2020$ / bbl | Dec. 31, 2019$ / shares$ / bbl | Dec. 31, 2019$ / shares | Dec. 31, 2018$ / shares |
Accounting Policies [Line Items] | ||||||
Common stock, par value (in dollars per share) | $ / shares | $ 0.001 | $ 0.001 | $ 0.001 | |||
Oil, approximate market price | $ / bbl | 60 | |||||
Total Proved Reserves, PV percentage | 9.00% | |||||
Common stock | ||||||
Accounting Policies [Line Items] | ||||||
Number of shares issued for 100 shares holding | shares | 1 | |||||
Number of shares converted into one share | shares | 100 | |||||
Maximum | ||||||
Accounting Policies [Line Items] | ||||||
Oil, approximate market price | $ / bbl | 20 | |||||
Term Loan | Subsequent event | ||||||
Accounting Policies [Line Items] | ||||||
Term for new agreement prior to event of default | 15 days | |||||
Waiver, right to require corresponding amendments within period from execution date | 90 days | |||||
Term Loan | Minimum | ||||||
Accounting Policies [Line Items] | ||||||
Asset Coverage Ratio | 1.50 |
BASIS OF PRESENTATION AND SUM_5
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Accounts Receivable Trade and Other (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||
Allowance for doubtful accounts | $ 0 | $ 0 |
Oil , natural gas and NGL sales | 18,211 | 16,408 |
Joint interest owners | 260 | 584 |
Commodity hedge contract receivables and other | 4,342 | 4,257 |
Receivable from sale of assets held for sale | 4,207 | |
Total accounts receivable trade and other | $ 27,020 | $ 21,249 |
BASIS OF PRESENTATION AND SUM_6
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Concentration of Credit Risk (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Concentration Risk [Line Items] | ||
Long-term contract | $ 54,284 | |
Percentage of working interest in wells | 100.00% | |
Customer concentration risk | Oil, natural gas and NGL | ||
Concentration Risk [Line Items] | ||
Exposure to risk (percentage) | 74.00% | |
Account receivable amount | $ 12,100 | |
Customer concentration risk | Gathering, processing, transportation and marketing services | ||
Concentration Risk [Line Items] | ||
Long-term contract | $ 54,300 | |
Accounts receivable | Customer concentration risk | Oil, natural gas and NGL | ||
Concentration Risk [Line Items] | ||
Exposure to risk (percentage) | 73.00% | |
Account receivable amount | $ 13,200 | |
Sales | Customer concentration risk | Purchaser A | ||
Concentration Risk [Line Items] | ||
Exposure to risk (percentage) | 60.00% | 34.00% |
Sales | Customer concentration risk | Purchaser B | ||
Concentration Risk [Line Items] | ||
Exposure to risk (percentage) | 21.00% | 26.00% |
Sales | Customer concentration risk | Purchaser C | ||
Concentration Risk [Line Items] | ||
Exposure to risk (percentage) | 23.00% |
BASIS OF PRESENTATION AND SUM_7
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Oil and Gas Properties (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Property, Plant and Equipment [Line Items] | ||
Depletion, depreciation and amortization expense | $ 92,334 | $ 62,814 |
Impairment expenses of proved oil and gas properties | 0 | 0 |
Impairment expenses of unproved oil and gas properties | 0 | 0 |
Oil and gas properties | ||
Property, Plant and Equipment [Line Items] | ||
Depletion, depreciation and amortization expense | $ 91,400 | $ 62,100 |
BASIS OF PRESENTATION AND SUM_8
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Other Property (Details) | 12 Months Ended |
Dec. 31, 2019 | |
Minimum | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives | 3 years |
Maximum | |
Property, Plant and Equipment [Line Items] | |
Estimated useful lives | 20 years |
BASIS OF PRESENTATION AND SUM_9
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Revenue Recognition (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2019USD ($)item | Dec. 31, 2018USD ($) | |
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||
Number of types of contracts | item | 3 | |
Period within which settlement is received | 2 months | |
Accounts receivable balance from contracts with customers | $ | $ 18.2 | $ 16.4 |
BASIS OF PRESENTATION AND SU_10
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Stock Based Compensation (Details) | 12 Months Ended |
Dec. 31, 2019 | |
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | |
Period of share holder return | 3 years |
BASIS OF PRESENTATION AND SU_11
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Defined Contribution Plan (Details) - USD ($) $ in Millions | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES | ||
Company contributions | $ 0.6 | $ 0.3 |
BASIS OF PRESENTATION AND SU_12
BASIS OF PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES - Industry Segment (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019USD ($)segment | Dec. 31, 2018USD ($) | |
Segment Reporting Information [Line Items] | ||
Number of reportable segments | segment | 1 | |
Exploration expense | $ 337 | $ 3,339 |
Cooper Basin | ||
Segment Reporting Information [Line Items] | ||
Exploration expense | $ 700 | |
Cooper Basin | Maximum | ||
Segment Reporting Information [Line Items] | ||
Exploration expense | $ 100 |
OIL AND GAS PROPERTIES (Details
OIL AND GAS PROPERTIES (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Oil and gas properties, successful efforts method: | ||
Unproved | $ 25,037 | $ 48,049 |
Proved | 1,090,774 | 925,551 |
Work in progress | 7,097 | 12,948 |
Total | 1,122,908 | 986,548 |
Accumulated depletion, depreciation and amortization | (379,961) | (293,598) |
Total oil and gas properties, net | 742,947 | 692,950 |
Capitalized interest | 2,300 | 1,500 |
Impairment of proved properties | $ 9,990 | $ 43,828 |
ACQUISITIONS AND DISPOSITIONS -
ACQUISITIONS AND DISPOSITIONS - Narrative (Details) - Discontinued operations closed by sale $ in Millions | 12 Months Ended | |
Dec. 31, 2019USD ($)aBoeitem | Oct. 01, 2019USD ($) | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Number of producing wells | item | 19 | |
Area of wells | a | 6,100 | |
Production of wells per day | Boe | 1,200 | |
Dimmit County, Texas | ||
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | ||
Consideration | $ 21.5 | |
Consideration receivable | $ 4.2 |
ACQUISITIONS AND DISPOSITIONS_2
ACQUISITIONS AND DISPOSITIONS - Assets and Liabilities (Details) $ in Thousands | Apr. 23, 2018USD ($)aitem | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Oil and gas properties | |||
Proved | $ 173,750 | ||
Unproved | 43,642 | ||
Liabilities Assumed: | |||
Trade and other payables | (80) | ||
Asset retirement obligation | (1,522) | ||
Net assets acquired | 215,790 | ||
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC | |||
Business Acquisition [Line Items] | |||
Area of wells acquired | a | 21,900 | ||
Cash paid for consideration | $ 215,800 | ||
Adjustments to consideration | $ 5,800 | ||
Gross production wells | item | 132 | ||
pro forma financial information | |||
Revenue | 174,700 | ||
Income (loss) before income taxes | (7,700) | ||
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC | General and administrative expenses | |||
Liabilities Assumed: | |||
Acquisition costs | 13,700 | ||
Acquisition costs expensed | $ 12,400 | $ 1,300 |
ACQUISITIONS AND DISPOSITIONS_3
ACQUISITIONS AND DISPOSITIONS - Revenues And Direct Operating Expenses (Details) - USD ($) $ in Thousands | 3 Months Ended | 8 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | |
Business Acquisition [Line Items] | |||||||||||
Income (loss) from operations: | $ (11,944) | $ 24,126 | $ 13,572 | $ (31,804) | $ 83,609 | $ (13,202) | $ (47,852) | $ (9,738) | $ (6,050) | $ 12,817 | |
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC | |||||||||||
Business Acquisition [Line Items] | |||||||||||
Revenues | $ 64,507 | ||||||||||
Direct Operating Expenses | (45,194) | ||||||||||
Income (loss) from operations: | $ 19,313 |
ASSETS HELD FOR SALE (Details)
ASSETS HELD FOR SALE (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Assets held for sale: | ||
Oil and gas properties - Dimmit County, Texas | $ 23,471 | |
Liabilities related to assets held for sale: | ||
Asset retirement obligations | (193) | |
Impairment expense | $ 9,990 | 43,828 |
Assets held for sale | ||
Assets held for sale: | ||
Oil and gas properties - Dimmit County, Texas | 23,471 | |
Liabilities related to assets held for sale: | ||
Asset retirement obligations | (193) | |
Net assets held for sale | 23,278 | |
Proved Oil And Gas Eagle Ford Formation assets located in Dimmit County, Texas | ||
Liabilities related to assets held for sale: | ||
Impairment expense | $ 10,000 | $ 43,000 |
ACCRUED LIABILITIES (Details)
ACCRUED LIABILITIES (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2016item | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | |
Oil and natural gas properties: | |||
Capital expenditures | $ 4,168 | $ 12,879 | |
Re-fracture liability | 764 | 900 | |
Lease operating and workover expenses and other | 7,393 | 6,586 | |
Accrued interest payable | 6,885 | 458 | |
General and administrative expense | 6,894 | 4,462 | |
Finance lease liabilities | 305 | ||
Total accrued liabilities | 26,409 | 25,285 | |
Number of wells to be refractured | item | 5 | ||
Agreement term | 5 years | ||
Long-term re-fracture liability | $ 700 | $ 1,100 |
LEASES (Details)
LEASES (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2019 | Dec. 31, 2018 | Jan. 01, 2019 | |
Practical expedients | true | ||
Easement arrangements | true | ||
Use hindsight | true | ||
Lease liability | $ 17,331 | ||
Lease right-of-use assets | 17,331 | ||
Finance Lease, Liability | $ 734 | ||
Rent expense | $ 3,600 | ||
Option to extend the lease | True | ||
Option to terminate the lease | True | ||
ASU 2016-02 | Restatement adjustment | |||
Lease liability | $ 11,500 | ||
Lease right-of-use assets | $ 11,400 | ||
Vehicles | |||
Finance Lease, Liability | 200 | ||
Office Equipment | |||
Finance Lease, Liability | $ 100 |
LEASES - Summary of right-of-us
LEASES - Summary of right-of-use assets and estimated lease liabilities (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Right-of-use assets | |
Operating lease right-of-use assets | $ 17,331 |
Financial Position | us-gaap:OperatingLeaseRightOfUseAsset |
Finance lease right-of-use assets | $ 747 |
Financial Position | us-gaap:PropertyPlantAndEquipmentNet |
Total right-of-use assets | $ 18,078 |
Lease liabilities | |
Operating lease liabilities - current | $ 7,720 |
Financial Position | us-gaap:OperatingLeaseLiabilityCurrent |
Operating lease liabilities - non-current | $ 9,611 |
Financial Position | us-gaap:OperatingLeaseLiabilityNoncurrent |
Finance lease liabilities - current | $ 305 |
Financial Position | us-gaap:AccruedLiabilitiesCurrent |
Finance lease liabilities - non-current | $ 429 |
Financial Position | us-gaap:OtherLiabilitiesNoncurrent |
Total lease liabilities | $ 18,065 |
Additions of operating and finance lease right-of-use | 18,078 |
Right-of-use assets in exchange for new operating lease obligations | 17,358 |
Right-of-use assets in exchange for new finance lease obligations | $ 640 |
LEASES - Summary of lease terms
LEASES - Summary of lease terms and discount rates (Details) | Dec. 31, 2019 |
Weighted Average Remaining Lease Term (years) | |
Operating Leases | 5 years 2 months 19 days |
Finance Leases | 2 years 6 months 29 days |
Weighted Average Discount Rate | |
Operating Leases | 4.73% |
Finance Leases | 4.69% |
LEASES - Summary of total lease
LEASES - Summary of total lease cost (Details) $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Property, Plant and Equipment [Line Items] | |
Operating lease cost | $ 11,729 |
Finance lease cost: | |
Amortization of right-of-use assets | 187 |
Interest on lease liabilities | 20 |
Total finance lease cost | 207 |
Shot-term lease cost | 1,065 |
Variable lease cost | 1,395 |
Sublease income | 150 |
Drilling Rig | |
Property, Plant and Equipment [Line Items] | |
Operating lease cost | $ 6,300 |
LEASES - Summary of supplementa
LEASES - Summary of supplemental cash flow information (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Cash paid for amounts included in the measurement of lease liabilities | ||
Operating cash flows from operating leases | $ 5,271 | |
Operating cash flows from finance leases | 20 | |
Investing cash flows from operating leases | 6,308 | |
Financing cash flows from finance leases | 187 | $ 11 |
Operating lease liability additions | 17,358 | |
Finance lease liability additions | $ 640 |
LEASES - Summary of lease oblig
LEASES - Summary of lease obligations (Details) $ in Thousands | Dec. 31, 2019USD ($) |
Operating leases | |
2020 | $ 7,848 |
2021 | 4,061 |
2022 | 2,819 |
2023 | 2,192 |
2024 | 845 |
Thereafter | 1,481 |
Total | 19,246 |
Less interest | (1,915) |
Total discounted lease payments | 17,331 |
Finance Leases | |
2020 | 312 |
2021 | 305 |
2022 | 150 |
2023 | 12 |
Total | 779 |
Less interest | (45) |
Total discounted lease payments | 734 |
Additions of operating and finance lease right-of-use | 18,078 |
Additional lease obligations | $ 18,065 |
LEASES - Summary of future mini
LEASES - Summary of future minimum contractual payments for long-term leases (Details) $ in Thousands | Dec. 31, 2018USD ($) |
Operating Leases | |
2019 | $ 2,087 |
2020 | 1,376 |
2021 | 602 |
2022 | 141 |
2023 | 83 |
Thereafter | 964 |
Total lease payments | 5,253 |
Capital Leases | |
2019 | 97 |
2020 | 98 |
2021 | 90 |
2022 | 15 |
2023 | 12 |
Total lease payments | 312 |
Less interest | (26) |
Total discounted lease payments | $ 286 |
Financial Position | us-gaap:OperatingLeaseLiabilityCurrent us-gaap:OperatingLeaseLiabilityNoncurrent |
Drilling Rig | |
Operating Leases | |
2019 | $ 4,106 |
Total lease payments | $ 4,106 |
LONG-TERM DEBT - Summary of lon
LONG-TERM DEBT - Summary of long-term debt (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 | Apr. 23, 2018 | Dec. 31, 2017 |
Line of Credit Facility [Line Items] | ||||
Total long-term debt | $ 365,000 | $ 315,000 | $ 192,000 | |
Deferred financing fees, net of accumulated amortization | (11,510) | (14,196) | $ (16,700) | |
Total credit facilities, net of deferred financing fees | 353,490 | 300,804 | ||
Revolving Facility | ||||
Line of Credit Facility [Line Items] | ||||
Total long-term debt | 115,000 | 65,000 | ||
Term Loan | ||||
Line of Credit Facility [Line Items] | ||||
Total long-term debt | $ 250,000 | $ 250,000 |
LONG-TERM DEBT - Narrative (Det
LONG-TERM DEBT - Narrative (Details) $ in Thousands | Apr. 23, 2018USD ($) | Apr. 30, 2019 | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Jan. 31, 2020USD ($) | Dec. 31, 2017USD ($) |
Line of Credit Facility [Line Items] | ||||||
Current borrowing capacity | $ 87,500 | |||||
Maximum borrowing capacity | 250,000 | |||||
Debt instrument, carrying amount | $ 365,000 | $ 315,000 | $ 192,000 | |||
Production prepayment | 11,800 | |||||
Deferred finance fee | $ 16,700 | 11,510 | 14,196 | |||
Available borrowing capacity | $ 38,600 | |||||
Write-off of deferred financing fees | 251 | |||||
Total Proved Reserves, PV percentage | 9.00% | |||||
Revolving Facility | ||||||
Line of Credit Facility [Line Items] | ||||||
Maximum borrowing capacity | $ 250,000 | |||||
Debt instrument, carrying amount | $ 115,000 | $ 65,000 | ||||
Interest rate | 4.75% | 5.40% | ||||
Letters of credit outstanding | $ 16,400 | |||||
Elected borrowing commitment | $ 190,000 | |||||
Revolving Facility | Subsequent event | ||||||
Line of Credit Facility [Line Items] | ||||||
Maximum borrowing capacity | $ 500,000 | |||||
Available borrowing capacity | 58,600 | |||||
Borrowing base | $ 210,000 | |||||
Revolving Facility | Maximum | ||||||
Line of Credit Facility [Line Items] | ||||||
Leverage Ratio | 3.5 | |||||
Revolving Facility | Minimum | ||||||
Line of Credit Facility [Line Items] | ||||||
Current Ratio | 1 | |||||
Interest Coverage Ratio | 1.5 | |||||
Revolving Facility | LIBOR | Maximum | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt instrument, variable rate | 3.50% | 3.25% | ||||
Revolving Facility | LIBOR | Minimum | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt instrument, variable rate | 2.50% | 2.25% | ||||
Term Loan | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt instrument, carrying amount | $ 250,000 | $ 250,000 | ||||
Interest rate | 10.10% | 10.81% | ||||
Term Loan | Minimum | ||||||
Line of Credit Facility [Line Items] | ||||||
Interest Coverage Ratio | 1.5 | |||||
Asset Coverage Ratio | 1.50 | |||||
Term Loan | LIBOR | ||||||
Line of Credit Facility [Line Items] | ||||||
Debt instrument, variable rate | 8.00% | |||||
Term Loan | Base Rate | Minimum | ||||||
Line of Credit Facility [Line Items] | ||||||
Interest rate | 9.00% |
ASSET RETIREMENT OBLIGATIONS (D
ASSET RETIREMENT OBLIGATIONS (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | |
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward] | ||||
Balance, beginning of year | $ 3,489 | $ 1,549 | ||
Additional liability incurred | 145 | 195 | ||
Obligations settled | (85) | (29) | ||
Obligations on assets acquired | 1,522 | |||
Obligations on assets sold | (232) | |||
Accretion expense | 336 | 252 | ||
Balance, end of year | 3,653 | 3,489 | ||
Liabilities related to assets held for sale | $ 193 | |||
Long-term | $ 3,653 | 3,296 | ||
Total | $ 3,653 | $ 3,489 | $ 3,653 | $ 3,489 |
INCOME TAXES - Narrative (Detai
INCOME TAXES - Narrative (Details) - USD ($) $ in Thousands | Mar. 27, 2020 | Dec. 31, 2019 | Dec. 31, 2018 |
Income tax expense | $ (4,518) | $ 13,957 | |
Pre-tax loss | (44,108) | (8,976) | |
Unrecognized tax benefits | 0 | ||
Withholding tax payable | 2,300 | ||
EFF | |||
Pre change losses | 248,500 | ||
Federal NOL | 292,400 | ||
Australian NOL | $ 26,200 | ||
Operating Loss Carryforwards, Limitations on Use | $42.3 | ||
Prior To The CARES Act | Tax years beginning January 1, 2019 and 2020 | |||
Net interest expense deduction limit as a percentage of adjusted taxable income | 30.00% | ||
COVID-19 pandemic | The CARES Act | Subsequent event | |||
Percentage of taxable income limitation eliminated to allow companies to fully utilize NOLs | 80.00% | ||
NOLs allowed to be carried back, term | 5 years | ||
COVID-19 pandemic | The CARES Act | Subsequent event | Tax years beginning January 1, 2019 and 2020 | |||
Net interest expense deduction limit as a percentage of adjusted taxable income | 50.00% | ||
UNITED STATES | |||
Deemed interest payments received from US subsidiaries | $ 20,700 | ||
AUSTRALIA | |||
Deferred Tax Assets, Operating Loss Carryforwards, Not Subject to Expiration | $ 15,600 |
INCOME TAXES - Provision (Detai
INCOME TAXES - Provision (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
INCOME TAXES | ||
Current income tax expense - Federal | $ 2,301 | |
Deferred income tax expense (benefit) | ||
Federal | $ (8,281) | (5,555) |
State | 11 | 318 |
Foreign | (503) | (2,929) |
Total deferred income tax (expense) benefit | (8,773) | (8,166) |
Income tax provision (benefit) | 4,255 | 19,822 |
Total income tax expense (benefit) | $ (4,518) | $ 13,957 |
INCOME TAXES - Reconciliation (
INCOME TAXES - Reconciliation (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
INCOME TAXES | ||
Income tax benefit at the federal statutory rate | $ (9,263) | $ (1,885) |
State income taxes - net of federal income tax benefits | 10 | 290 |
Stock-based compensation | 114 | 839 |
Nondeductible expenses | 519 | 1,055 |
Change in valuation allowance | 4,255 | 19,822 |
Foreign tax rates | (166) | (877) |
Australian Tax Losses on U.S. Restructuring | (3,284) | |
Deemed interest payment due to U.S. restructuring | (4,350) | |
U.S. withholding tax net of foreign tax credit | 2,301 | |
Other | 13 | 46 |
Total income tax expense (benefit) | $ (4,518) | $ 13,957 |
INCOME TAXES - Net Deferred Tax
INCOME TAXES - Net Deferred Taxes (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Deferred tax assets (liabilities): | ||
Net operating loss carryforward | $ 76,624 | $ 70,560 |
Business interest carryforward | 10,474 | 7,054 |
Stock-based compensation | 93 | 102 |
Statutory depletion carryforward | 2,927 | 2,977 |
Unrealized (gain) loss on commodity derivative | 1,147 | (6,453) |
Lease obligations | 3,735 | |
Property, plant and equipment | 82 | |
Property, plant and equipment | (122) | |
Other assets | 524 | 1,688 |
Total deferred tax assets | 95,606 | 75,806 |
Valuation allowance | (64,898) | (60,643) |
Deferred tax assets, net | 30,708 | 15,163 |
Basis of oil and gas properties | (33,950) | (26,819) |
Lease assets | (3,896) | |
Total deferred tax liabilities | (37,846) | (26,819) |
Deferred tax liabilities, net | $ (7,138) | $ (11,656) |
DERIVATIVE FINANCIAL INSTRUME_3
DERIVATIVE FINANCIAL INSTRUMENTS - Narrative (Details) - Revolving Facility | 12 Months Ended |
Dec. 31, 2019 | |
Projected Period Thirty Six Months | |
Derivative | |
Hedging period of proved reserves classified as Developed Producing Reserves | 36 months |
Maximum | Projected Period Thirty Six Months | |
Derivative | |
Hedging percentage of reasonably projected oil and gas production | 85.00% |
Maximum | Projected Period Thirty Seven to Sixty Months | |
Derivative | |
Hedging percentage of reasonably projected oil and gas production | 75.00% |
Hedging period of proved reserves classified as Developed Producing Reserves | 60 months |
Minimum | Projected Period Thirty Six Months | |
Derivative | |
Hedging percentage of reasonably projected oil and gas production | 50.00% |
Minimum | Projected Period Thirty Seven to Sixty Months | |
Derivative | |
Hedging period of proved reserves classified as Developed Producing Reserves | 25 months |
DERIVATIVE FINANCIAL INSTRUME_4
DERIVATIVE FINANCIAL INSTRUMENTS - Derivative Positions (Details) | 3 Months Ended | 12 Months Ended |
Mar. 31, 2020MMBTU$ / MMBTU$ / bblbbl | Dec. 31, 2019MMBTU$ / MMBTU$ / bblbbl | |
Propane | 2020 | ||
Derivative | ||
Volumes (Bbl) | bbl | 271,000 | |
Weighted Average Price per Bbl, MMBtu | 0.70 | |
WTI - HOU | 2020 | ||
Derivative | ||
Volumes (Bbl) | bbl | 720,000 | |
Weighted Average Price per Bbl, MMBtu | 2.98 | |
WTI - HOU | 2021 | ||
Derivative | ||
Volumes (Bbl) | bbl | 120,000 | |
Weighted Average Price per Bbl, MMBtu | 2.53 | |
Swaps | WTI | 2020 | ||
Derivative | ||
Volumes (Bbl) | bbl | 1,074,000 | |
Weighted Average Price per Bbl, MMBtu | 57.17 | |
Swaps | WTI | 2020 | Subsequent event | ||
Derivative | ||
Volumes (Bbl) | bbl | 720,000 | |
Weighted Average Price per Bbl, MMBtu | 49.39 | |
Swaps | WTI | 2021 | ||
Derivative | ||
Volumes (Bbl) | bbl | 216,000 | |
Weighted Average Price per Bbl, MMBtu | 54.84 | |
Swaps | WTI | 2021 | Subsequent event | ||
Derivative | ||
Volumes (Bbl) | bbl | 1,980,000 | |
Weighted Average Price per Bbl, MMBtu | 48.38 | |
Swaps | HH | 2020 | ||
Derivative | ||
Volumes (MMBtu) | MMBTU | 1,890,000 | |
Weighted Average Price per Bbl, MMBtu | $ / MMBTU | 2.70 | |
Swaps | HH | 2021 | ||
Derivative | ||
Volumes (MMBtu) | MMBTU | 1,050,000 | |
Weighted Average Price per Bbl, MMBtu | $ / MMBTU | 2.69 | |
Swaps | HH | 2021 | Subsequent event | ||
Derivative | ||
Volumes (MMBtu) | MMBTU | 600,000 | |
Weighted Average Price per Bbl, MMBtu | $ / MMBTU | 2.67 | |
Swaps | HH | 2022 | ||
Derivative | ||
Volumes (MMBtu) | MMBTU | 720,000 | |
Weighted Average Price per Bbl, MMBtu | $ / MMBTU | 2.76 | |
Swaps | HSC | 2020 | ||
Derivative | ||
Volumes (MMBtu) | MMBTU | 120,000 | |
Weighted Average Price per Bbl, MMBtu | $ / MMBTU | 2.53 | |
Swaps | HSC | 2021 | ||
Derivative | ||
Volumes (MMBtu) | MMBTU | 240,000 | |
Weighted Average Price per Bbl, MMBtu | $ / MMBTU | 2.50 | |
Swaps | HSC | 2022 | ||
Derivative | ||
Volumes (MMBtu) | MMBTU | 360,000 | |
Weighted Average Price per Bbl, MMBtu | $ / MMBTU | 2.54 | |
Swaps | HSC | 2023 | ||
Derivative | ||
Volumes (MMBtu) | MMBTU | 240,000 | |
Weighted Average Price per Bbl, MMBtu | $ / MMBTU | 2.64 | |
Collars [Member] | WTI | 2020 | ||
Derivative | ||
Volumes (Bbl) | bbl | 672,000 | |
Weighted Average Price per Bbl, MMBtu - Floor | 54.47 | |
Weighted Average Price per Bbl, MMBtu - Ceiling | 61.82 | |
Collars [Member] | WTI | 2021 | ||
Derivative | ||
Volumes (Bbl) | bbl | 216,000 | |
Weighted Average Price per Bbl, MMBtu - Floor | 45 | |
Weighted Average Price per Bbl, MMBtu - Ceiling | 65 | |
Collars [Member] | WTI | 2022 | ||
Derivative | ||
Volumes (Bbl) | bbl | 228,000 | |
Weighted Average Price per Bbl, MMBtu - Floor | 40 | |
Weighted Average Price per Bbl, MMBtu - Ceiling | 66 | |
Collars [Member] | WTI | 2023 | ||
Derivative | ||
Volumes (Bbl) | bbl | 160,000 | |
Weighted Average Price per Bbl, MMBtu - Floor | 40 | |
Weighted Average Price per Bbl, MMBtu - Ceiling | 63.10 | |
Collars [Member] | HH | 2020 | ||
Derivative | ||
Volumes (MMBtu) | MMBTU | 120,000 | |
Weighted Average Price per Bbl, MMBtu - Floor | $ / MMBTU | 2.50 | |
Weighted Average Price per Bbl, MMBtu - Ceiling | $ / MMBTU | 2.95 | |
Collars [Member] | HSC | 2020 | ||
Derivative | ||
Volumes (MMBtu) | MMBTU | 96,000 | |
Weighted Average Price per Bbl, MMBtu - Floor | $ / MMBTU | 2.60 | |
Weighted Average Price per Bbl, MMBtu - Ceiling | $ / MMBTU | 2.91 | |
Three-Way Collars | WTI | 2020 | ||
Derivative | ||
Volumes (Bbl) | bbl | 300,000 | |
Weighted Average Price per Bbl, MMBtu - Ceiling | 59.60 | |
Three-Way Collars | WTI | 2021 | ||
Derivative | ||
Volumes (Bbl) | bbl | 300,000 | |
Weighted Average Price per Bbl, MMBtu - Ceiling | 57.50 | |
Three-Way Collars | WTI | 2022 | ||
Derivative | ||
Volumes (Bbl) | bbl | 300,000 | |
Weighted Average Price per Bbl, MMBtu - Ceiling | 56.90 | |
Three-Way Collars | WTI | Purchased | 2020 | ||
Derivative | ||
Weighted Average Price per Bbl, MMBtu - Floor | 50 | |
Three-Way Collars | WTI | Purchased | 2021 | ||
Derivative | ||
Weighted Average Price per Bbl, MMBtu - Floor | 50 | |
Three-Way Collars | WTI | Purchased | 2022 | ||
Derivative | ||
Weighted Average Price per Bbl, MMBtu - Floor | 50 | |
Three-Way Collars | WTI | Sold | 2020 | ||
Derivative | ||
Weighted Average Price per Bbl, MMBtu - Floor | 35 | |
Three-Way Collars | WTI | Sold | 2021 | ||
Derivative | ||
Weighted Average Price per Bbl, MMBtu - Floor | 35 | |
Three-Way Collars | WTI | Sold | 2022 | ||
Derivative | ||
Weighted Average Price per Bbl, MMBtu - Floor | 35 |
DERIVATIVE FINANCIAL INSTRUME_5
DERIVATIVE FINANCIAL INSTRUMENTS - Interest Rate Swaps (Details) - Derivative interest rate swaps $ in Thousands | 12 Months Ended |
Dec. 31, 2019USD ($) | |
Derivative | |
Floor interest rate | 1.00% |
July 11, 2019 - July 11, 2020 | |
Derivative | |
Notional Amount | $ 187,500 |
Fixed Rate | 3.016% |
Portion of Term Loan Face Amount | 75.00% |
July 11, 2020 - July 11, 2021 | |
Derivative | |
Notional Amount | $ 125,000 |
Fixed Rate | 3.072% |
Portion of Term Loan Face Amount | 50.00% |
July 11, 2021 - July 11, 2022 | |
Derivative | |
Notional Amount | $ 125,000 |
Fixed Rate | 3.061% |
Portion of Term Loan Face Amount | 50.00% |
July 13, 2022 - May 23, 2023 | |
Derivative | |
Notional Amount | $ 125,000 |
Fixed Rate | 3.042% |
Portion of Term Loan Face Amount | 50.00% |
DERIVATIVE FINANCIAL INSTRUME_6
DERIVATIVE FINANCIAL INSTRUMENTS - Offsetting of Derivative Assets (Details) - Not designated as ASC 815 Hedges - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Derivative Asset | ||
Gross Recognized Assets | $ 5,885 | $ 49,503 |
Net Recognized Fair Value Assets | 2,093 | 32,318 |
Derivative commodity contracts | Derivative assets current | ||
Derivative Asset | ||
Gross Recognized Assets | 2,863 | 24,877 |
Gross Amount Offset | (1,648) | (562) |
Net Recognized Fair Value Assets | 1,215 | 24,315 |
Derivative commodity contracts | Derivative assets non-current | ||
Derivative Asset | ||
Gross Recognized Assets | 2,637 | 8,403 |
Gross Amount Offset | (1,759) | (400) |
Net Recognized Fair Value Assets | 878 | 8,003 |
Derivative interest rate swaps | Derivative assets current | ||
Derivative Asset | ||
Gross Recognized Assets | 8 | 5,081 |
Gross Amount Offset | (8) | (5,081) |
Derivative interest rate swaps | Derivative assets non-current | ||
Derivative Asset | ||
Gross Recognized Assets | 377 | 11,142 |
Gross Amount Offset | $ (377) | $ (11,142) |
DERIVATIVE FINANCIAL INSTRUME_7
DERIVATIVE FINANCIAL INSTRUMENTS - Offsetting of Derivative Liabilities (Details) - Not designated as ASC 815 Hedges - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Offsetting Liabilities | ||
Gross Recognized Liabilities | $ 11,855 | $ 20,199 |
Net Recognized Fair Value Liabilities | 8,063 | 3,014 |
Gross Recognized Assets/ Liabilities | (5,970) | 29,304 |
Net Recognized Fair Value Assets/ Liabilities | (5,970) | 29,304 |
Derivative liabilities current | ||
Offsetting Liabilities | ||
Gross Recognized Liabilities | 6,050 | 6,079 |
Net Recognized Fair Value Liabilities | 4,394 | 436 |
Derivative liabilities non-current | ||
Offsetting Liabilities | ||
Gross Recognized Liabilities | 5,805 | 14,120 |
Net Recognized Fair Value Liabilities | 3,669 | 2,578 |
Derivative commodity contracts | Derivative liabilities current | ||
Offsetting Liabilities | ||
Gross Recognized Liabilities | 3,946 | 787 |
Gross Amounts Offset | (1,648) | (562) |
Net Recognized Fair Value Liabilities | 2,298 | 225 |
Derivative commodity contracts | Derivative liabilities non-current | ||
Offsetting Liabilities | ||
Gross Recognized Liabilities | 1,761 | 1,051 |
Gross Amounts Offset | (1,759) | (400) |
Net Recognized Fair Value Liabilities | 2 | 651 |
Derivative interest rate swaps | Derivative liabilities current | ||
Offsetting Liabilities | ||
Gross Recognized Liabilities | 2,104 | 5,292 |
Gross Amounts Offset | (8) | (5,081) |
Net Recognized Fair Value Liabilities | 2,096 | 211 |
Derivative interest rate swaps | Derivative liabilities non-current | ||
Offsetting Liabilities | ||
Gross Recognized Liabilities | 4,044 | 13,069 |
Gross Amounts Offset | (377) | (11,142) |
Net Recognized Fair Value Liabilities | $ 3,667 | $ 1,927 |
DERIVATIVE FINANCIAL INSTRUME_8
DERIVATIVE FINANCIAL INSTRUMENTS - Gain (Loss) Recognized (Details) - Not designated as ASC 815 Hedges - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Derivative Instruments, Gain (Loss) | ||
Gain (Loss) Recognized in Income | $ (24,812) | $ 44,619 |
Foreign currency | Gain on foreign currency derivative financial instruments | ||
Derivative Instruments, Gain (Loss) | ||
Gain (Loss) Recognized in Income | 6,838 | |
Derivative commodity contracts | Gain (loss) on commodity derivative financial instruments | ||
Derivative Instruments, Gain (Loss) | ||
Gain (Loss) Recognized in Income | (20,542) | 40,216 |
Derivative interest rate swaps | Interest expense | ||
Derivative Instruments, Gain (Loss) | ||
Gain (Loss) Recognized in Income | $ (4,270) | $ (2,435) |
FAIR VALUE MEASUREMENT - Assets
FAIR VALUE MEASUREMENT - Assets and Liabilities (Details) - Fair Value, Recurring - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Liabilities measured at fair value | ||
Derivative liabilities | $ (8,063) | $ (3,014) |
Net fair value | (5,970) | 29,304 |
Derivative commodity contracts | ||
Assets measured at fair value | ||
Derivative assets | 2,093 | 32,318 |
Liabilities measured at fair value | ||
Derivative liabilities | (2,300) | (876) |
Derivative interest rate swaps | ||
Liabilities measured at fair value | ||
Derivative liabilities | (5,763) | (2,138) |
Level 2 | ||
Liabilities measured at fair value | ||
Derivative liabilities | (8,063) | (3,014) |
Net fair value | (5,970) | 29,304 |
Level 2 | Derivative commodity contracts | ||
Assets measured at fair value | ||
Derivative assets | 2,093 | 32,318 |
Liabilities measured at fair value | ||
Derivative liabilities | (2,300) | (876) |
Level 2 | Derivative interest rate swaps | ||
Liabilities measured at fair value | ||
Derivative liabilities | $ (5,763) | $ (2,138) |
FAIR VALUE MEASUREMENT - Transf
FAIR VALUE MEASUREMENT - Transfers Between Levels (Details) - USD ($) | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
FAIR VALUE MEASUREMENT | ||
Fair value transfer of assets from level 1 to level 2 | $ 0 | $ 0 |
Fair value transfer of assets from level 2 to level 1 | 0 | 0 |
Fair value transfer of liabilities from level 1 to level 2 | 0 | 0 |
Fair value transfer of liabilities from level 2 to level 1 | 0 | 0 |
Fair value transfer of assets into level 3 | 0 | 0 |
Fair value transfer of assets out of level 3 | 0 | 0 |
Fair value transfer of liabilities into level 3 | 0 | 0 |
Fair value transfer of liabilities out of level 3 | $ 0 | $ 0 |
FAIR VALUE MEASUREMENT - Credit
FAIR VALUE MEASUREMENT - Credit Facilities (Details) $ in Thousands | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2017USD ($) |
Debt Instrument [Line Items] | |||
Principal debt outstanding | $ 365,000 | $ 315,000 | $ 192,000 |
Debt, valuation technique | Us-gaap:ValuationTechniqueDiscountedCashFlowMember | ||
Debt, Input | Us-gaap:MeasurementInputPrepaymentRateMember | ||
Maximum | |||
Debt Instrument [Line Items] | |||
Debt measurement input | 0.0325 | ||
Minimum | |||
Debt Instrument [Line Items] | |||
Debt measurement input | 0.0225 | ||
Revolving Facility | |||
Debt Instrument [Line Items] | |||
Principal debt outstanding | $ 115,000 | 65,000 | |
Term Loan | |||
Debt Instrument [Line Items] | |||
Principal debt outstanding | 250,000 | $ 250,000 | |
Fair value of its Term Loan | $ 249,000 |
FAIR VALUE MEASUREMENT - Non Re
FAIR VALUE MEASUREMENT - Non Recurring (Details) $ in Thousands | Dec. 31, 2018USD ($) |
FAIR VALUE MEASUREMENT | |
Assets held for sale | $ 23,471 |
Fair Value, Nonrecurring | Net Carrying Value | |
FAIR VALUE MEASUREMENT | |
Assets held for sale | 23,471 |
Fair Value, Nonrecurring | Level 3 | Fair Value | |
FAIR VALUE MEASUREMENT | |
Assets held for sale | $ 23,471 |
EARNINGS PER SHARE - Reconcilia
EARNINGS PER SHARE - Reconciliation (Details) - USD ($) $ / shares in Units, $ in Thousands | 3 Months Ended | 12 Months Ended | ||||||||
Dec. 31, 2019 | Sep. 30, 2019 | Jun. 30, 2019 | Mar. 31, 2019 | Dec. 31, 2018 | Sep. 30, 2018 | Jun. 30, 2018 | Mar. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | |
EARNINGS PER SHARE | ||||||||||
Net loss | $ (18,321) | $ 13,297 | $ 2,643 | $ (37,209) | $ 72,720 | $ (20,249) | $ (49,673) | $ (25,731) | $ (39,590) | $ (22,933) |
Weighted average shares : | ||||||||||
Weighted average common shares outstanding, basic | 6,874,170 | 5,236,524 | ||||||||
Weighted average common shares outstanding, diluted | 6,874,170 | 5,236,524 | ||||||||
Net loss per share: | ||||||||||
Basic and diluted | $ (5.76) | $ (4.38) |
EARNINGS PER SHARE - Narrative
EARNINGS PER SHARE - Narrative (Details) | 1 Months Ended | 12 Months Ended | |
Nov. 30, 2019 | Dec. 31, 2019shares | Dec. 31, 2018shares | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Conversion ratio | 0.01 | 0.01 | |
Service - based Awards | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Diluted effect of Incremental shares related to restricted share units | 320 | 786 |
EQUITY - Reverse Stock Split (D
EQUITY - Reverse Stock Split (Details) | 1 Months Ended | 12 Months Ended | |||
Nov. 30, 2019 | Dec. 31, 2019shares | Nov. 01, 2019shares | Oct. 31, 2019shares | Dec. 31, 2018shares | |
EQUITY | |||||
Reverse stock split | 0.01 | 0.01 | |||
Number of ordinary outstanding shares | 6,875,672 | 6,900,000 | 687,000,000 | 6,874,622 |
EQUITY - Equity Offerings (Deta
EQUITY - Equity Offerings (Details) $ in Millions | 12 Months Ended |
Dec. 31, 2018USD ($)shares | |
EQUITY | |
Number of shares issued | shares | 5,614,446 |
Proceeds from capital raise | $ | $ 243 |
EQUITY - Stock Based Compensati
EQUITY - Stock Based Compensation (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
EQUITY | ||
Recognized stock based compensation expense | $ 504 | $ 515 |
EQUITY - Restricted Share Units
EQUITY - Restricted Share Units (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2020 | Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Recognized stock based compensation expense | $ 504 | $ 515 | |
Forecast | |||
Weighted Average Fair Value at Grant Date | |||
Vested RSUs that will be issued | 375 | ||
Restricted Share Units | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 38,373 | 71,175 | |
Number of RSUs | |||
Outstanding at beginning (in shares) | 84,929 | 91,339 | 33,804 |
Granted (in shares) | 38,373 | 71,175 | |
Vested (in shares) | (1,425) | (6,916) | |
Forfeited (in shares) | (43,358) | (6,724) | |
Outstanding at ending (in shares) | 84,929 | 91,339 | |
Weighted Average Fair Value at Grant Date | |||
Outstanding at beginning (per share) | $ 22.97 | $ 34.37 | $ 166.87 |
Granted (per share) | 20.31 | 18.80 | |
Vested (per share) | 61.56 | 361.03 | |
Forfeited (per share) | 51.20 | 198.37 | |
Outstanding at ending (per share) | $ 22.97 | $ 34.37 | |
Total RSUs outstanding | 84,929 | 91,339 | |
Restricted Share Units | March 15, 2016 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 4,428 | ||
Restricted Share Units | May 27, 2016 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 4,342 | ||
Restricted Share Units | June 29, 2016 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 497 | ||
Restricted Share Units | February 17, 2017 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 3,411 | 4,572 | |
Restricted Share Units | May 25, 2017 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 3,724 | 3,724 | |
Restricted Share Units | October 23, 2017 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 745 | 745 | |
Weighted Average Fair Value at Grant Date | |||
Vesting period (in years) | 3 years | ||
Restricted Share Units | October 23, 2017 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 375 | 750 | |
Restricted Share Units | December 29, 2017 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 497 | 1,106 | |
Restricted Share Units | December 26, 2018 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 30,414 | 35,587 | |
Weighted Average Fair Value at Grant Date | |||
Vesting period (in years) | 3 years | ||
Restricted Share Units | December 26, 2018 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 15,207 | 35,588 | |
Restricted Share Units | May 5, 2019 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 1,775 | ||
Restricted Share Units | May 5, 2019 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 5,325 | ||
Restricted Share Units | May 31, 2019 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 15,637 | ||
Restricted Share Units | May 31, 2019 | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Units awarded | 7,819 |
EQUITY - RSUs Grant Date, Fair
EQUITY - RSUs Grant Date, Fair Value and Vesting Conditions (Details) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Stock-based compensation | $ 504 | $ 515 |
Restricted Share Units | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of RSUs | 38,373 | 71,175 |
Fair Value at Grant Date | $ 20.31 | $ 18.80 |
Unvested compensation expense | $ 500 | |
Weighted average prices | $ 22.02 | $ 70.85 |
Weighted average remaining contractual life (in years) | 1 year | |
Fair value, expected to vest | $ 100 | |
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 5, 2019 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of RSUs | 5,325 | |
Fair Value at Grant Date | $ 16.35 | |
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 5, 2019 | Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 200.00% | |
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 5, 2019 | Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 0.00% | |
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 31, 2019 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of RSUs | 15,637 | |
Fair Value at Grant Date | $ 16.13 | |
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 31, 2019 | Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 200.00% | |
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date May 31, 2019 | Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 0.00% | |
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date December 26, 2018 | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of RSUs | 35,587 | |
Fair Value at Grant Date | $ 16.44 | |
Restricted Share Units | Vesting Based on 3 year TSR as compared to the XOP index, Grant Date December 26, 2018 | Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 0.00% | |
Restricted Share Units | Vesting Based on 2019 EBITDA per Debt Adjusted Share | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of RSUs | 3,909 | 8,897 |
Fair Value at Grant Date | $ 24.92 | $ 21.16 |
Restricted Share Units | Vesting Based on 2019 EBITDA per Debt Adjusted Share | Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 200.00% | 200.00% |
Restricted Share Units | Vesting Based on 2019 EBITDA per Debt Adjusted Share | Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 0.00% | 0.00% |
Restricted Share Units | Vesting Based on 2020 EBITDA per Debt Adjusted Share | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of RSUs | 3,909 | 8,897 |
Fair Value at Grant Date | $ 24.92 | $ 21.16 |
Restricted Share Units | Vesting Based on 2020 EBITDA per Debt Adjusted Share | Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 200.00% | 200.00% |
Restricted Share Units | Vesting Based on 2020 EBITDA per Debt Adjusted Share | Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 0.00% | 0.00% |
Restricted Share Units | Vesting Based on 2019 Production per Debt Adjusted Share | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of RSUs | 3,909 | 8,897 |
Fair Value at Grant Date | $ 24.92 | $ 21.16 |
Restricted Share Units | Vesting Based on 2019 Production per Debt Adjusted Share | Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 200.00% | 200.00% |
Restricted Share Units | Vesting Based on 2019 Production per Debt Adjusted Share | Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 0.00% | 0.00% |
Restricted Share Units | Vesting Based on 2020 Production per Debt Adjusted Share | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of RSUs | 3,909 | 8,897 |
Fair Value at Grant Date | $ 24.92 | $ 21.16 |
Restricted Share Units | Vesting Based on 2020 Production per Debt Adjusted Share | Maximum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 200.00% | 200.00% |
Restricted Share Units | Vesting Based on 2020 Production per Debt Adjusted Share | Minimum | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Vesting percentage | 0.00% | 0.00% |
Restricted Share Units | Vests on 3rd anniversary of award | ||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | ||
Number of RSUs | 1,775 | |
Fair Value at Grant Date | $ 29.49 |
COMMITMENTS AND CONTINGENCIES -
COMMITMENTS AND CONTINGENCIES - Narrative (Details) $ in Thousands, $ in Millions | 12 Months Ended | |||
Dec. 31, 2019AUD ($) | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | Dec. 31, 2019USD ($) | |
Lessee, Lease, Description [Line Items] | ||||
Exploration costs incurred | $ 335 | $ 2,789 | ||
Exploration expense | 337 | 3,339 | ||
Litigation settlement expense | 700 | |||
Cooper Basin | ||||
Lessee, Lease, Description [Line Items] | ||||
Commitment to fund exploratory drilling | $ 10.6 | $ 7,500 | ||
Exploration costs incurred | 7.1 | 5,000 | ||
Remaining commitment to fund exploratory drilling | $ 3.5 | $ 2,500 | ||
Exploration expense | 700 | |||
Maximum | Cooper Basin | ||||
Lessee, Lease, Description [Line Items] | ||||
Exploration expense | 100 | |||
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC | ||||
Lessee, Lease, Description [Line Items] | ||||
Deficiency payment | 2,300 | $ 2,800 | ||
Exploration expense | $ 100 |
COMMITMENTS AND CONTINGENCIES_2
COMMITMENTS AND CONTINGENCIES - Total Commitments (Details) - USD ($) $ in Thousands | Dec. 31, 2019 | Dec. 31, 2018 |
Minimum revenue commitment | ||
2020 | $ 21,807 | |
2021 | 21,485 | |
2022 | 10,992 | |
Total | 54,284 | |
Hydrocarbon gathering and handling agreement | ||
Minimum revenue commitment | ||
2020 | 14,297 | |
2021 | 13,972 | |
2022 | 6,675 | |
Total | 34,944 | |
Crude oil and condensate purchase agreements | ||
Minimum revenue commitment | ||
2020 | 4,710 | |
2021 | 7,513 | |
2022 | 4,317 | |
Total | 16,540 | |
Gas processing agreement | ||
Minimum revenue commitment | ||
2020 | 2,017 | |
Total | 2,017 | |
Gas transportation agreements | ||
Minimum revenue commitment | ||
2020 | 783 | |
Total | 783 | |
Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC | ||
Minimum revenue commitment | ||
Total | $ 15,800 | $ 11,100 |
SUBSEQUENT EVENTS (Details)
SUBSEQUENT EVENTS (Details) - Term Loan | Apr. 29, 2020 | Dec. 31, 2019 |
Subsequent event | ||
Subsequent Event [Line Items] | ||
Term for new agreement prior to event of default | 15 days | |
LIBOR | ||
Subsequent Event [Line Items] | ||
Debt instrument, variable rate | 8.00% |
SUPPLEMENTAL DISCLOSURES ABOU_3
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Costs Incurred (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2019 | Dec. 31, 2018 | |
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) | ||
Proved | $ 173,750 | |
Unproved | $ 177 | 45,252 |
Exploration costs | 335 | 2,789 |
Development costs | 149,766 | 181,463 |
Development costs associated with non-producing wells in progress | 7,100 | 12,900 |
Cost incurred relating to unproved properties held for sale | 0 | 1,000 |
Development cost related to assets held for sale | $ 8,400 | $ 5,300 |
SUPPLEMENTAL DISCLOSURES ABOU_4
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - SEC Oil and Gas Reserve Information (Details) | 12 Months Ended | |
Dec. 31, 2019MBoeMMcfMBbls | Dec. 31, 2018MBoeMMcfMBbls | |
Proved reserves: | ||
Discounted rate | 10.00% | 10.00% |
Proved developed and undeveloped reserve, net energy, beginning balance (MBoe) | MBoe | 93,241 | 47,079 |
Revisions of previous estimates (MBoe) | MBoe | (23,168) | (10,716) |
Extensions and discoveries (MBoe) | MBoe | 39,649 | 11,904 |
Purchases of reserves in-place (MBoe) | MBoe | 48,503 | |
Production (MBoe) | MBoe | (4,836) | (3,508) |
Sales of reserves in-place (MBoe) | MBoe | (3,814) | (21) |
Proved developed and undeveloped reserve, net energy, ending balance (MBoe) | MBoe | 101,072 | 93,241 |
Proved developed reserves (MBoe) | MBoe | 24,611 | 27,197 |
Proved undeveloped reserves (MBoe) | MBoe | 76,461 | 66,044 |
Oil | ||
Proved reserves: | ||
Proved developed and undeveloped reserve, net, beginning balance | 58,629 | 27,987 |
Revisions of previous estimates | (14,358) | (5,138) |
Extensions and discoveries | 23,018 | 7,577 |
Purchases of reserves in-place | 30,474 | |
Production | (3,077) | (2,256) |
Sales of reserves in-place | (1,424) | (15) |
Proved developed and undeveloped reserve, net, ending balance | 62,788 | 58,629 |
Proved developed reserves | 16,101 | 16,742 |
Proved undeveloped reserves | 46,687 | 41,887 |
Gas | ||
Proved reserves: | ||
Proved developed and undeveloped reserve, net, beginning balance | MMcf | 108,841 | 59,409 |
Revisions of previous estimates | MMcf | (27,504) | (14,257) |
Extensions and discoveries | MMcf | 52,297 | 12,889 |
Purchases of reserves in-place | MMcf | 55,367 | |
Production | MMcf | (5,768) | (4,534) |
Sales of reserves in-place | MMcf | (6,962) | (33) |
Proved developed and undeveloped reserve, net, ending balance | MMcf | 120,904 | 108,841 |
Proved developed reserves | MMcf | 26,930 | 33,169 |
Proved undeveloped reserves | MMcf | 93,974 | 75,672 |
Natural gas liquid sales | ||
Proved reserves: | ||
Proved developed and undeveloped reserve, net, beginning balance | 16,472 | 9,190 |
Revisions of previous estimates | (4,225) | (3,201) |
Extensions and discoveries | 7,915 | 2,179 |
Purchases of reserves in-place | 8,801 | |
Production | (798) | (497) |
Sales of reserves in-place | (1,230) | |
Proved developed and undeveloped reserve, net, ending balance | 18,134 | 16,472 |
Proved developed reserves | 4,022 | 4,927 |
Proved undeveloped reserves | 14,112 | 11,545 |
SUPPLEMENTAL DISCLOSURES ABOU_5
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - SEC Oil and Gas Reserve Information Other (Details) $ in Millions | 12 Months Ended | |
Dec. 31, 2019USD ($)MBoelocation | Dec. 31, 2018MBoe | |
Oil and Gas, Delivery Commitment [Line Items] | ||
Proved undeveloped reserves (MBoe) | 76,461 | 66,044 |
Duration over which future development costs expects to fund with operating cash flows | 5 years | |
Future development costs associated with proved undeveloped reserves | $ | $ 1,173.2 | |
Expected proved reserves operating cash flow | $ | $ 1,503.7 | |
Revisions of previous estimates (MBoe) | (23,168) | (10,716) |
Extensions and discoveries (MBoe) | 39,649 | 11,904 |
Proved developed reserves, sales of reserves in-place (MBoe) | 2,078 | |
Proved undeveloped reserves, sales of reserves in-place (MBoe) | 1,736 | |
EFF | ||
Oil and Gas, Delivery Commitment [Line Items] | ||
Proved undeveloped reserves (MBoe) | 76,461 | 66,044 |
Increase in proved undeveloped reserves (MBoe) | 10,417 | |
Extensions and discoveries, undeveloped (MBoe) | 36,535 | |
Revisions of previous estimates, undeveloped (MBoe) | 19,881 | |
Number of proved undeveloped locations | location | 50 | |
Number of locations on acquired assets | location | 80 | |
Proved undeveloped reserves on acquired assets | 35,630 | |
Conversion to proved developed reserves (MBoe) | 4,501 | |
Expected duration within which reserves will be spud | 5 years | |
Revisions of previous estimates (MBoe) | (23,168) | (10,716) |
Extensions and discoveries (MBoe) | 39,649 | 11,904 |
SUPPLEMENTAL DISCLOSURES ABOU_6
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Standardized Measure of Future Net Cash Flow (Details) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2019 | Dec. 31, 2018 | Dec. 31, 2019 | Dec. 31, 2018 | |
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract] | ||||
Discounted rate | 10.00% | 10.00% | ||
Cash inflows | $ 4,148,426 | $ 4,733,751 | ||
Production costs | (1,348,892) | (1,318,059) | ||
Development costs | (1,231,467) | (1,143,083) | ||
Income tax expense | (183,680) | (343,068) | ||
Net cash flow | 1,384,387 | 1,929,541 | ||
10% annual discount rate | (709,288) | (976,916) | ||
Standardized measure of discounted future net cash flow | $ 675,099 | $ 952,625 | $ 675,099 | $ 952,625 |
Standardized Measure, beginning of year | 952,625 | 366,747 | ||
Sales, net of production costs | (141,329) | (113,073) | ||
Net change in sales prices, net of production costs | (422,811) | 201,784 | ||
Extensions and discoveries, net of future production and development costs | 258,433 | 206,179 | ||
Changes in future development costs | 283,154 | 63,297 | ||
Previously estimated development costs incurred during the period | 84,739 | 94,673 | ||
Revision of quantity estimates | (308,312) | (198,956) | ||
Accretion of discount | 110,985 | 38,124 | ||
Change in income taxes | 79,728 | (142,730) | ||
Purchases of reserves in-place | 525,547 | |||
Sales of reserves in-place | (47,059) | (220) | ||
Change in production rates and other | (175,054) | (88,747) | ||
Standardized Measure, end of year | $ 675,099 | $ 952,625 |
SUPPLEMENTAL DISCLOSURES ABOU_7
SUPPLEMENTAL DISCLOSURES ABOUT OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED) - Impact of Pricing (Details) | 12 Months Ended | |
Dec. 31, 2019$ / Mcf$ / bbl | Dec. 31, 2018$ / Mcf$ / bbl | |
Oil | ||
Reserve Quantities [Line Items] | ||
Average prices | 56.05 | 66.34 |
Gas | ||
Reserve Quantities [Line Items] | ||
Average prices | $ / Mcf | 2.75 | 3.50 |
Natural gas liquid sales | ||
Reserve Quantities [Line Items] | ||
Average prices | 16.35 | 28.15 |
QUARTERLY FINANCIAL DATA (UNA_3
QUARTERLY FINANCIAL DATA (UNAUDITED) (Details) $ / shares in Units, $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | ||||||||
Nov. 30, 2019 | Dec. 31, 2019USD ($)$ / shares | Sep. 30, 2019USD ($)$ / shares | Jun. 30, 2019USD ($)$ / shares | Mar. 31, 2019USD ($)$ / shares | Dec. 31, 2018USD ($)$ / shares | Sep. 30, 2018USD ($)$ / shares | Jun. 30, 2018USD ($)$ / shares | Mar. 31, 2018USD ($)$ / shares | Dec. 31, 2019USD ($) | Dec. 31, 2018USD ($) | |
QUARTERLY FINANCIAL DATA (UNAUDITED) | |||||||||||
Revenues | $ 51,842 | $ 51,097 | $ 52,901 | $ 47,740 | $ 58,336 | $ 53,824 | $ 28,737 | $ 24,036 | $ 203,580 | $ 164,933 | |
Income (loss) from operations | (11,944) | 24,126 | 13,572 | (31,804) | 83,609 | (13,202) | (47,852) | (9,738) | (6,050) | 12,817 | |
Net income (loss) | $ (18,321) | $ 13,297 | $ 2,643 | $ (37,209) | $ 72,720 | $ (20,249) | $ (49,673) | $ (25,731) | $ (39,590) | $ (22,933) | |
Income (loss) per share - basic | $ / shares | $ (2.67) | $ 1.93 | $ 0.38 | $ (5.41) | $ 10.58 | $ (2.95) | $ (8.63) | $ (19.75) | |||
Income (loss) per share - diluted | $ / shares | $ (2.67) | $ 1.93 | $ 0.38 | $ (5.41) | $ 10.58 | $ (2.95) | $ (8.63) | $ (19.75) | |||
Conversion ratio | 0.01 | 0.01 |