Document and Entity Information
Document and Entity Information | 12 Months Ended |
Dec. 31, 2017shares | |
Document and Entity Information | |
Entity Registrant Name | Sundance Energy Australia Ltd |
Entity Central Index Key | 1,326,089 |
Document Type | 20-F |
Document Period End Date | Dec. 31, 2017 |
Amendment Flag | false |
Current Fiscal Year End Date | --12-31 |
Entity Well-known Seasoned Issuer | No |
Entity Voluntary Filers | No |
Entity Current Reporting Status | Yes |
Entity Filer Category | Non-accelerated Filer |
Entity Common Stock, Shares Outstanding | 1,253,249,528 |
Document Fiscal Year Focus | 2,017 |
Document Fiscal Period Focus | FY |
CONSOLIDATED STATEMENTS OF PROF
CONSOLIDATED STATEMENTS OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME (LOSS) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CONSOLIDATED STATEMENTS OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME (LOSS) | |||
Oil and natural gas revenue | $ 104,399 | $ 66,609 | $ 92,191 |
Lease operating expenses | (22,416) | (12,937) | (18,455) |
Production taxes | (6,613) | (4,200) | (6,043) |
General and administrative expense | (18,345) | (12,110) | (17,176) |
Depreciation and amortisation expense | (58,361) | (48,147) | (94,584) |
Impairment expense | (5,583) | (10,203) | (321,918) |
Exploration expense | (30) | (7,925) | |
Finance costs, net of amounts capitalized | (13,491) | (12,219) | (9,418) |
Loss on debt extinguishment | (1,451) | ||
Loss on sale of non-current assets | (1,461) | 790 | |
Loss on derivative financial instruments | (2,894) | (12,761) | 15,256 |
Other income, net | 457 | 2,009 | (2,240) |
Loss before income tax | (24,308) | (43,989) | (370,973) |
Income tax benefit (expense) | 1,873 | (1,705) | 107,138 |
Loss attributable to owners of the Company | (22,435) | (45,694) | (263,835) |
Items that may be reclassified subsequently to profit or loss: | |||
Exchange differences arising on translation of foreign operations (no income tax effect) | 708 | (532) | (478) |
Other comprehensive loss | 708 | (532) | (478) |
Total comprehensive loss attributable to owners of the Company | $ (21,727) | $ (46,226) | $ (264,313) |
Loss per share | |||
Basic earnings | $ (1.8) | $ (5.2) | $ (47.7) |
Diluted earnings | $ (1.8) | $ (5.2) | $ (47.7) |
CONSOLIDATED STATEMENTS OF FINA
CONSOLIDATED STATEMENTS OF FINANCIAL POSITION - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
CURRENT ASSETS | ||
Cash and cash equivalents | $ 5,761 | $ 17,463 |
Trade and other receivables | 3,966 | 9,786 |
Derivative financial instruments | 383 | |
Income tax receivable | 40 | 5,204 |
Other current assets | 3,472 | 4,078 |
Assets held for sale | 61,064 | 18,309 |
TOTAL CURRENT ASSETS | 74,686 | 54,840 |
NON-CURRENT ASSETS | ||
Development and production assets | 338,796 | 338,709 |
Exploration and evaluation expenditure | 34,979 | 34,366 |
Property and equipment | 1,246 | 1,211 |
Income tax receivable, non-current | 4,688 | |
Derivative financial instruments | 223 | 279 |
Deferred tax assets | 2,683 | |
TOTAL NON-CURRENT ASSETS | 379,932 | 377,248 |
TOTAL ASSETS | 454,618 | 432,088 |
CURRENT LIABILITIES | ||
Trade and other payables | 9,051 | 3,579 |
Accrued expenses | 39,051 | 19,995 |
Production prepayment | 18,194 | |
Derivative financial instruments | 5,618 | 4,579 |
Provisions, current | 1,158 | 2,726 |
Liabilities related to assets held for sale | 1,064 | 941 |
TOTAL CURRENT LIABILITIES | 74,136 | 31,820 |
NON-CURRENT LIABILITIES | ||
Credit facilities, net of deferred financing fees | 189,310 | 188,249 |
Restoration provision | 7,567 | 7,072 |
Other provisions, non-current | 2,158 | 3,299 |
Derivative financial instruments | 3,728 | 3,215 |
Other non-current liabilities | 368 | 610 |
TOTAL NON-CURRENT LIABILITIES | 203,131 | 202,445 |
TOTAL LIABILITIES | 277,267 | 234,265 |
NET ASSETS | 177,351 | 197,823 |
EQUITY | ||
Issued capital | 372,764 | 373,585 |
Share based payments reserve | 16,250 | 14,174 |
Foreign currency translation reserve | (1,134) | (1,842) |
Accumulated deficit | (210,529) | (188,094) |
TOTAL EQUITY | $ 177,351 | $ 197,823 |
CONSOLIDATED STATEMENTS OF CHAN
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY - USD ($) $ in Thousands | Issued capital | Share-Based Payments Reserve | Foreign Currency Translation Reserve | Accumulated Deficit | Total |
Balance at Dec. 31, 2014 | $ 306,853 | $ 7,550 | $ (832) | $ 121,435 | $ 435,006 |
(Loss) profit attributable to owners of the Company | (263,835) | (263,835) | |||
Other comprehensive gain (loss) for the year | (478) | (478) | |||
Total comprehensive loss attributable to owners of the Company | (478) | (263,835) | (264,313) | ||
Shares issued in connection with private placement/ business combinations | 1,576 | 1,576 | |||
Share based compensation value of services | 4,100 | 4,100 | |||
Balance at Dec. 31, 2015 | 308,429 | 11,650 | (1,310) | (142,400) | 176,369 |
(Loss) profit attributable to owners of the Company | (45,694) | (45,694) | |||
Other comprehensive gain (loss) for the year | (532) | (532) | |||
Total comprehensive loss attributable to owners of the Company | (532) | (45,694) | (46,226) | ||
Shares issued in connection with private placement/ business combinations | 67,499 | 67,499 | |||
Cost of capital, net of tax | (2,343) | (2,343) | |||
Share based compensation value of services | 2,524 | 2,524 | |||
Balance at Dec. 31, 2016 | 373,585 | 14,174 | (1,842) | (188,094) | 197,823 |
(Loss) profit attributable to owners of the Company | (22,435) | (22,435) | |||
Other comprehensive gain (loss) for the year | 708 | 708 | |||
Total comprehensive loss attributable to owners of the Company | 708 | (22,435) | (21,727) | ||
Derecognition of deferred tax asset | (821) | (821) | |||
Share based compensation value of services | 2,076 | 2,076 | |||
Balance at Dec. 31, 2017 | $ 372,764 | $ 16,250 | $ (1,134) | $ (210,529) | $ 177,351 |
CONSOLIDATED STATEMENTS OF CASH
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CASH FLOWS FROM OPERATING ACTIVITIES | |||
Receipts from sales | $ 112,534 | $ 64,749 | $ 99,423 |
Payments to suppliers and employees | (40,000) | (32,634) | (49,639) |
Settlements of restoration provision | (132) | (110) | (71) |
Interest received | 107 | ||
Payments for (receipts from) commodity derivative settlements, net | (1,428) | 10,630 | 11,736 |
Premium payments for commodity derivatives | (690) | ||
Income taxes received, net | 3,999 | 25 | 3,603 |
Other operating activities | (197) | ||
NET CASH PROVIDED BY OPERATING ACTIVITIES | 74,776 | 42,660 | 64,469 |
CASH FLOWS FROM INVESTING ACTIVITIES | |||
Payments for development expenditure | (101,043) | (64,130) | (144,316) |
Payments for exploration expenditure | (8,351) | (2,852) | (20,339) |
Payments for acquisition of oil and gas properties | (23,506) | (15,023) | |
Sale of non-current assets | 15,348 | 7,141 | 41 |
Payments for acquisition related costs | (578) | ||
Payments for property and equipment | (657) | (295) | (371) |
Other investing activities | 2,200 | 3,651 | (185) |
NET CASH USED IN INVESTING ACTIVITIES | (92,503) | (79,991) | (180,771) |
CASH FLOWS FROM FINANCING ACTIVITIES | |||
Proceeds from the issuance of shares | 67,499 | ||
Payments for costs of capital raisings | (3,330) | ||
Borrowing costs paid, net of capitalized portion | (12,381) | (11,753) | (6,889) |
Deferred financing fees capitalized | (4,708) | ||
Payments for foreign currency derivatives | (390) | ||
Proceeds from borrowings | 47,199 | 207,000 | |
Repayments from borrowings | (28,755) | (250) | (145,000) |
NET CASH PROVIDED BY FINANCING ACTIVITIES | 6,063 | 51,776 | 50,403 |
Net increase (decrease) in cash held | (11,664) | 14,445 | (65,899) |
Cash and cash equivalents at beginning of year | 17,463 | 3,468 | 69,217 |
Effect of exchange rates on cash | (38) | (450) | 150 |
CASH AND CASH EQUIVALENTS AT END OF YEAR | $ 5,761 | $ 17,463 | $ 3,468 |
STATEMENT OF SIGNIFICANT ACCOUN
STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES | 12 Months Ended |
Dec. 31, 2017 | |
STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES | |
STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES | NOTE 1 - STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES The consolidated financial report of Sundance Energy Australia Limited (“SEAL”) and its wholly owned subsidiaries, (collectively, the “Company”, “Consolidated Group” or “Group”), for the year ended 31 December 2017 was authorised for issuance in accordance with a resolution of the Board of Directors on 29 March 2018. Refer to Note 36 for listing of the Company’s significant subsidiaries. The Group is a for-profit entity for the purpose of preparing the financial report. The principal activities of the Group during the financial year are the exploration for, development and production of oil and natural gas in the United States of America, and the continued expansion of its mineral acreage portfolio in the United States of America. Basis of Preparation The consolidated financial report is a general purpose financial report that has been prepared in accordance with Australian Accounting Standards, Australian Accounting Interpretations, other authoritative pronouncements of the Australian Accounting Standards Board (“AASB”) and the Corporations Act 2001. These consolidated financial statements comply with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Material accounting policies adopted in the preparation of this financial report are presented below. They have been consistently applied unless otherwise stated. The consolidated financial statements are prepared on a historical basis, except for the revaluation of certain non-current assets and financial instruments, as explained in the accounting policies below. The consolidated financial statements are presented in US dollars and all values are rounded to the nearest thousand (US$’000), except where stated otherwise. Principles of Consolidation The consolidated financial statements incorporate the assets and liabilities as at December 31 2017 and 2016, and the results for the years then ended, of Sundance Energy Australia Limited (“SEAL”) and the entities it controls. A controlled entity is any entity over which SEAL is exposed, or has rights to variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. As at 31 December 2017 and 2016, all of its controlled entities were wholly-owned. All inter-group balances and transactions between entities in the Group, including any recognised profits or losses, are eliminated on consolidation. a) Income Tax The income tax expense for the period comprises current income tax expense and deferred income tax expense. Current income tax expense charged to the statement of profit or loss is the tax payable on taxable income calculated using applicable income tax rates enacted, or substantially enacted, as at the reporting date. Current tax liabilities/(assets) are therefore measured at the amounts expected to be paid to/(recovered from) the relevant taxation authority. Deferred income tax expense reflects movements in deferred tax asset and deferred tax liability balances during the period. Current and deferred income tax expense/(income) is charged or credited directly to equity instead of the statement of profit or loss when the tax relates to items that are credited or charged directly to equity. Deferred tax assets and liabilities are ascertained based on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred tax assets also result where amounts have been fully expensed but future tax deductions are available. No deferred income tax will be recognised from the initial recognition of an asset or liability, excluding a business combination, where there is no effect on accounting or taxable profit or loss. Deferred tax assets and liabilities are calculated at the tax rates that are expected to apply to the period when the asset recognised or the liability is settled, based on tax rates enacted or substantively enacted at the reporting date. Their measurement also reflects the manner in which management expects to recover or settle the carrying amount of the related asset or liability. Deferred tax assets relating to temporary differences and unused tax losses are recognised only to the extent that it is probable that future taxable profit will be available against which the benefits of the deferred tax asset can be utilized. Where temporary differences exist in relation to investments in subsidiaries, branches, associates, and joint ventures, deferred tax assets and liabilities are not recognised where the timing of the reversal of the temporary difference can be controlled and it is not probable that the reversal will occur in the foreseeable future. Current tax assets and liabilities are offset where a legally enforceable right of set-off exists and it is intended that net settlement or simultaneous realisation and settlement of the respective asset and liability will occur. Deferred tax assets and liabilities are offset where a legally enforceable right of set-off exists, the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where it is intended that net settlement or simultaneous realisation and settlement of the respective asset and liability will occur in future periods in which significant amounts of deferred tax assets or liabilities are expected to be recovered or settled. Tax Consolidation Sundance Energy Australia Limited and its wholly-owned Australian controlled entities have implemented the income tax consolidation regime, with Sundance Energy Australia Limited being the head company of the consolidated group. Under this regime the group entities are taxed as a single taxpayer. In addition to its own current and deferred tax amounts, Sundance Energy Australia Limited, as head company, also recognises the current tax liabilities (or assets) and the deferred tax assets arising from unused tax losses and unused tax credits assumed from controlled entities in the tax consolidated group. b) Exploration and Evaluation Expenditure Exploration and evaluation expenditures incurred are accumulated in respect of each identifiable area of interest. These costs are capitalised to the extent that they are expected to be recouped through the successful development of the area or where activities in the area have not yet reached a stage that permits reasonable assessment of the existence of economically recoverable reserves. Any such estimates and assumptions may change as new information becomes available. If, after the expenditure is capitalised, information becomes available suggesting that the recovery of the expenditure is unlikely, for example a dry hole, the relevant capitalised amount is written off in the consolidated statement of profit or loss and other comprehensive income in the period in which new information becomes available. The costs of assets constructed within the Group includes the leasehold cost, geological and geophysical costs, and an appropriate proportion of fixed and variable overheads directly attributable to the exploration and acquisition of undeveloped oil and gas properties. When approval of commercial development of a discovered oil or gas field occurs, the accumulated costs for the relevant area of interest are transferred to development and production assets. The costs of developed and producing assets are amortised over the life of the area according to the rate of depletion of the proved and probable developed reserves. The costs associated with the undeveloped acreage are not subject to depletion. The carrying amounts of the Group’s exploration and evaluation assets are reviewed at each reporting date to determine whether any impairment indicators exist. Impairment indicators could include i) tenure over the licence area has expired during the period or will expire in the near future, and is not expected to be renewed, ii) substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is not budgeted or planned, iii) exploration for and evaluation of resources in the specific area have not led to the discovery of commercially viable quantities of resources, and the Group has decided to discontinue activities in the specific area, or iv) sufficient data exist to indicate that although a development is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or from sale. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made and any resulting impairment loss is recognized in the consolidated statement of profit or loss and other comprehensive income. The estimate of the recoverable amount is made consistent with the methods described under Impairment in (d) below. c) Development and Production Assets and Property and Equipment Development and production assets, and property and equipment are carried at cost less, where applicable, any accumulated depreciation, amortisation and impairment losses. The costs of assets constructed within the Group includes the cost of materials, direct labor, borrowing costs and an appropriate proportion of fixed and variable overheads directly attributable to the acquisition or development of oil and gas properties and facilities necessary for the extraction of resources. Repairs and maintenance are charged to the consolidated statement of profit or loss and comprehensive income during the financial period in which are they are incurred. Depreciation and Amortisation Expense Property and equipment are depreciated on a straight-line basis over their useful lives from the time the asset is held and ready for use. Leasehold improvements are depreciated over the shorter of either the unexpired period of the lease or the estimated useful life of the improvement. The depreciation rates used for each class of depreciable assets are: Class of Non-Current Asset Depreciation Rate Basis of Depreciation Property and Equipment 5 – 33 % Straight Line The Group uses the units-of-production method to amortise costs carried forward in relation to its development and production assets. For this approach, the calculation is based upon economically recoverable reserves over the life of an asset or group of assets. The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at the end of each reporting period. d) Impairment The carrying amount of development and production assets and property and equipment are reviewed at each reporting date to determine whether there is any indication of impairment. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made. Development and production assets are assessed for impairment on a cash-generating unit basis. A cash-generating unit (“CGU”) is the smallest grouping of assets that generates independent cash inflows. Management has assessed its CGUs as being an individual basin, which is the lowest level for which cash inflows are largely independent of those of other assets. Each of the Group’s development and production asset CGUs include all of its developed producing properties, shared infrastructure supporting its production and undeveloped acreage that the Group considers technically feasible and commercially viable. An impairment loss is recognized in the consolidated statement of profit and loss whenever the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount. Impairment losses recognised in respect of cash-generating units are allocated to reduce the carrying amount of the assets in the unit on a pro-rata basis. The recoverable amount of an asset is the greater of its fair value less costs to sell (“FVLCS”) or its value-in-use (“VIU”). In assessing VIU, an asset’s estimated future cash flows are discounted to their present value using an appropriate discount rate that reflects current market assessments of the time value of money and the risks specific to the assets/CGUs. The estimated future cash flows for the VIU calculation are based on estimates, the most significant of which are hydrocarbon reserves, future production profiles, commodity prices, operating costs and any future development costs necessary to produce the reserves. Estimates of future commodity prices are based on the Group’s best estimates of future market prices with reference to bank price surveys, external market analysts’ forecasts, and forward curves. The discount rates applied to the future forecast cash flows are based on a third party participant’s post-tax weighted average cost of capital, adjusted for the risk profile of the asset. Under a FVLCS calculation, the Group considers market data related to recent transactions for similar assets. In determining the fair value of the Group’s investment in shale properties, the Group considers a variety of valuation metrics from recent comparable transactions in the market. These metrics include price per flowing barrel of oil equivalent and undeveloped land values per net acre held. Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the group and the cost of the item can be measured reliably. An impairment loss is reversed if there has been an increase in the estimated recoverable amount of a previously impaired assets. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or depletion if no impairment loss had been recognized. The Company has not reversed an impairment loss during the years ended 31 December 2017, 2016 and 2015. If an entire CGU is disposed, gains and losses on disposals are determined by comparing proceeds with the carrying amount. These gains and losses are included in the statement of profit or loss. If a disposition is less than an entire CGU and the property had been previously subjected to amortization or impairment at the CGU level, and there would be no significant impact to the Company’s depletion rate, no gain or loss is recognized and the proceeds of the sale are treated as a cost reduction to the Company’s net book value of the CGU in which the assets were previously included. e) Leases The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at date of inception. The arrangement is assessed to determine whether its fulfillment is dependent on the use of a specific asset or assets and whether the arrangement conveys a right to use the asset, even if that right is not explicitly specified in an arrangement. Leases are classified as finance leases when the terms of the lease transfer substantially all the risks and benefits incidental to the ownership of the asset, but not the legal ownership to the entities in the Group. All other leases are classified as operating leases. Finance leases are capitalised by recording an asset and a liability at the lower of the amounts equal to the fair value of the leased property or the present value of the minimum lease payments, including any guaranteed residual values. Lease payments are allocated between the reduction of the lease liability and the lease interest expense for the period. Assets under financing leases are depreciated on a straight-line basis over the shorter of their estimated useful lives or the lease term. Lease payments for operating leases, where substantially all the risks and benefits remain with the lessor, are charged as expenses in the periods in which they are incurred. Lease incentives under operating leases are recognised as a liability and amortised on a straight-line basis over the life of the lease term. f) Financial Instruments Recognition and Initial Measurement Financial instruments, incorporating financial assets and financial liabilities, are recognised when the entity becomes a party to the contractual provisions of the instrument. Trade date accounting is adopted for financial assets that are delivered within timeframes established by marketplace convention. Financial instruments are initially measured at fair value plus transactions costs where the instrument is not classified at fair value through profit or loss. Transaction costs related to instruments classified at fair value through profit or loss are expensed to profit or loss immediately. Financial instruments are classified and measured as set out below. Derivative Financial Instruments The Group uses derivative financial instruments to economically hedge its exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity crude oil or natural gas price swap, option and costless collar contracts. Their use is subject to policies and procedures as approved by the Board of Directors. The Group does not trade in derivative financial instruments for speculative purposes. Derivative financial instruments, which do not qualify as “own-use”, are initially recognised at fair value and remeasured at each reporting period. The fair value of these derivative financial instruments is the estimated amount that the Group would receive or pay to terminate the contracts at the reporting date, taking into account current market prices and the current creditworthiness of the contract counterparties. The derivatives are valued on a mark to market valuation and the gain or loss on re-measurement to fair value is recognised through the statement of profit or loss and other comprehensive income. The Company has designated one oil marketing contract that meets the definition of a derivative as own-use, which under IFRS is not accounted for as a derivative. As a result, the revenues associated with such contract are recognized during the period when volumes are physically delivered. i) Financial assets are classified at fair value through profit or loss when they are acquired principally for the purpose of selling in the near-term. Realised and unrealised gains and losses arising from changes in fair value are included in profit or loss in the period in which they arise. ii) Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market and are subsequently measured at amortised cost using the effective interest rate method. Derecognition Financial assets are derecognised when the contractual right to receipt of cash flows expires or the asset is transferred to another party whereby the entity no longer has any significant continuing involvement in the risks and benefits associated with the asset. Financial liabilities are derecognised when the related obligations are either discharged, cancelled or expire. The difference between the carrying value of the financial liability extinguished or transferred to another party and the fair value of consideration paid, including the transfer of non-cash assets or liabilities assumed, is recognised in profit or loss. g) Foreign Currency Transactions and Balances Functional and Presentation Currency Both the functional currency and the presentation currency of the Group is US dollars. Some subsidiaries have Australian dollar functional currencies which are translated to the presentation currency. All operations of the Group are incurred at subsidiaries where the functional currency is the US dollar as its core oil and gas properties are located in the United States. Transactions and Balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the date of the transaction. Foreign currency monetary items are translated at the year-end exchange rate. Non-monetary items measured at historical cost continue to be carried at the exchange rate at the date of the transaction. Non-monetary items measured at fair value are reported at the exchange rate at the date when fair values were determined. Exchange differences arising on the translation of non-monetary items are recognised directly in equity to the extent that the gain or loss is directly recognised in equity, otherwise the exchange difference is recognised in the consolidated statement of profit or loss and other comprehensive income. Group Companies The financial results and position of foreign subsidiaries whose functional currency is different from the Group’s presentation currency are translated as follows: assets and liabilities are translated at year-end exchange rates prevailing at that reporting date; revenues and expenses are translated to USD using the exchange rate at the date of transaction; and retained profits and issued capital are translated at the exchange rates prevailing at the date of the transaction. Exchange differences arising on translation of foreign operations are transferred directly to the Group’s foreign currency translation reserve. These differences are recognised in the statement of profit or loss and other comprehensive income upon disposal of the foreign operation. h) Employee Benefits Employee benefits that are expected to be settled within one year have been measured at the amounts expected to be paid when the liability is settled. Equity - Settled Compensation The Group has an incentive compensation plan where employees may be issued shares and/or options. 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 group has a restricted share unit (“RSU”) plan to motivate management and employees to make decisions benefiting long-term value creation, retain management and employees and reward the achievement of the Group’s long-term goals. The target RSUs are generally based on goals established by the Remuneration and Nominations Committee and approved by the Board. The fair value of time-based RSUs is determined based on the price of the Company’s ordinary shares on the date of grant and the expense is recognized over the vesting period. Certain of its RSUs vest based on the achievement of metrics related to the Company’s 3‑year absolute shareholder return or total shareholder return as compared to its peer group, as defined. The Company uses 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 is 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 Australian Treasury bond relevant to the term of the RSU award. Deferred Cash Compensation In 2016 and 2017, the Group granted deferred cash compensation awards to certain employees, which may be earned through appreciation in the volume weighted average price of the Company’s ordinary shares over periods of one to three years. The awards may ultimately be settled in cash or fully vested RSUs at the discretion of the Board. The Group recognizes general and administrative expense for the deferred cash compensation to the extent to which the employees have rendered services, with a corresponding liability included within other noncurrent liabilities on the consolidated statement of financial position. The fair value of the deferred cash awards are estimated initially and at the end of each reporting period until settled, using a Monte Carlo model that takes into consideration the terms and conditions of the award. 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 U.S. Treasury bond relevant to the term of the award. i) Provisions Provisions are recognised when the group has a legal or constructive obligation, as a result of past events, for which it is probable that an outflow of economic benefits will result and that outflow can be reliably measured. As of 31 December 2017, the Company had recognized a provisions related to a third-party refracturing agreement ($3.3 million). j) Cash and Cash Equivalents Cash and cash equivalents include cash on hand, deposits held at call with banks, and other short-term highly liquid investments with original maturities of three months or less. k) Revenue Revenue from the sale of oil and natural gas is recognised upon the delivery of product to the purchaser and title transfers to the purchaser. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company had not recognized an imbalance on the consolidated statement of financial position as at 31 December 2017 and 2016. All revenue is stated net of royalties and transportation costs. l) Borrowing Costs Borrowing costs, including interest, directly attributable to the acquisition, construction or production of assets that necessarily take a substantial period of time to prepare for their intended use or sale are added to the cost of those assets until such time as the assets are substantially ready for their intended use or sale. Borrowings are recognised initially at fair value, net of transaction costs incurred. Subsequent to initial recognition, borrowings are stated as amortised cost with any difference between cost and redemption being recognised in the consolidated statement of profit or loss and other comprehensive income over the period of the borrowings on an effective interest basis. The Company capitalised eligible borrowing costs of $1.4 million and $1.1 million for the years ended 31 December 2017 and 2016, respectively. All other borrowing costs are recognised in the consolidated statement of profit or loss and other comprehensive income in the period in which they are incurred. m) Goods and Services Tax Expenses and assets are recognised net of the amount of Goods and Service Tax (“GST”), except where the amount of GST incurred is not recoverable from the Australian Tax Office. In these circumstances the GST is recognised as part of the cost of acquisition of the asset or as part of an item of the expense. Receivables and payables in the statement of financial position are shown inclusive of GST. Cash flows are presented in the consolidated statement of cash flows on a gross basis except for the GST component of investing and financing activities, which are disclosed as operating cash flows. n) Business Combinations A business combination is a transaction in which an acquirer obtains control of one or more businesses. The acquisition method of accounting is used to account for all business combinations regardless of whether equity instruments or other assets are acquired. The acquisition method is only applied to a business combination when control over the business is obtained. Subsequent changes in interests in a business where control already exists are accounted for as transactions between owners. The cost of the business combination is measured at fair value of the assets given, shares issued and liabilities incurred or assumed at the date of acquisition. Costs directly attributable to the business combination are expensed as incurred, except those directly and incrementally attributable to equity issuance. The excess of the consideration transferred, the amount of any non-controlling interest in the acquiree and the acquisition-date fair value of any previous equity interest in the acquiree over the fair value of the net identifiable asset acquired, if any, is recorded as goodwill. If those amounts are less than the fair value of the net identifiable assets of the subsidiary acquired and the measurement of all amounts has been reviewed, the difference is recognised directly in the consolidated statement of profit or loss and other comprehensive income as a gain on bargain purchase. Adjustments to the purchase price and excess on consideration transferred may be made up to one year from the acquisition date. o) Assets Held for Sale The Company classifies property as held for sale when management commits to a plan to sell the property, the plan has appropriate approvals, the sale of the property is highly probable within the next twelve months, and certain other criteria are met. At such time, the respective assets and liabilities are presented separately on the Company’s consolidated statement of financial position and amortisation is no longer recognized. Assets held for sale are reported at the lower of their carrying amount or their estimated fair value, less the costs to sell the assets. The Company recognizes an impairment loss if the current net book value of the property exceeds its fair value, less selling costs. As at 31 December 2017, based upon the Company’s intent and anticipated ability to sell an interest in these properties, the Company had classified its Dimmit County, Texas properties as held for sale. As at 31 December 2016 the Company had its Mississippian/Woodward properties classified as held for sale. p) Critical Accounting Estimates and Judgements The Directors evaluate estimates and judgements incorporated into the financial report based on historical knowledge and best available current information. Estimates assume a reasonable expectation of future events and are based on current trends and economic data obtained both externally and within the Group. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods. Management has made the following judgements, which have the most significant effect on the amounts recognised in the consolidated financial statements. Estimates of reserve quantities The estimated quantities of hydrocarbon reserves reported by the Group are integral to the calculation of amortisation (depletion) and to assessments of possible impairment of assets. Estimated reserve quantities are based upon interpretations of geological and geophysical models and assessment of the technical feasibility and commercial viability of producing the reserves. The Company engaged an independent petroleum engineering firm, Ryder Scott Company to prepare its reserve estimates which conform to SEC guidelines. These assessments require assumptions to be made regarding future development and production costs, commodity prices, exchange rates and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period, and as additional geological and production data are generated during the course of operations. Impairment of Non-Financial Assets The Group assesses impairment at each reporting date by evaluating conditions specific to the Group that may lead to impairment of assets. Where an indicator of impairment exists, the recoverable amount of the cash-generating unit to which the assets belong is then estimated based on the present value of future discounted cash flows. For development and production assets, the expected future cash flow estimation is based on a number of factors, variables and assumptions, the most important of which are estimates of reserves, future production profiles, commodity prices and costs. In most cases, the present value of future cash flows is most sensitive to estimates of future oil price and discount rates. A change in the modeled assumptions in isolation could materially change the recoverable amount. However, due to the interrelated nature of the assumptions, movements in any one variable can have an indirect impact on others and individual variables rarely change in isolation. Additionally, management can be expected to respond to some movements, to mitigate downsides and take advantage of upsides, as circumstances allow. Consequently, it is impracticable to estimate the indirect impact t |
BUSINESS COMBINATIONS
BUSINESS COMBINATIONS | 12 Months Ended |
Dec. 31, 2017 | |
BUSINESS COMBINATIONS | |
BUSINESS COMBINATIONS | NOTE 2 — BUSINESS COMBINATIONS Acquisitions in 2017 The Company did not complete any business combinations in 2017. Acquisitions in 2016 Acquisition #1 On 29 July 2016, the Company completed its acquisition of 5,050 net acres targeting the Eagle Ford in McMullen County, Texas, for a cash purchase price of $15.9 million. The assets acquired included approximately 26 gross (9.1 net) producing wells, which were primarily Sundance-operated prior to the acquisition. The Company acquired the assets to execute on its strategy of growing its Eagle Ford position. The following table reflects the fair value of the assets acquired and the liabilities assumed as at the date of acquisition (in thousands): Fair value of assets acquired: Development and production assets $ 16,628 Fair value of liabilities assumed: Restoration provision (747) Net assets acquired $ 15,881 Purchase price: Cash consideration $ 15,881 Total consideration paid $ 15,881 Revenues of $2.4 million and net income of $0.4 million (excluding the impact of income taxes) were generated from the acquired properties from 29 July 2016 through 31 December 2016. The Company did not incur any material acquisition costs related to the transaction. Acquisition #2 On 19 December 2016, the Company completed its acquisition of additional working interest in 23 gross (1.5 net) producing wells and 130 acres in McMullen County for cash consideration of $7.2 million. 12 gross (1.0 net) of the acquired wells are Sundance operated. The Company acquired the assets to execute on its strategy of growing its Eagle Ford position. The following table reflects the fair value of the assets acquired and the liabilities as at the date of acquisition (in thousands): Fair value of assets acquired: Development and production assets 7,348 Fair value of liabilities assumed: Restoration provision (118) Net assets acquired $ 7,230 Purchase price: Cash consideration $ 7,230 Total consideration paid $ 7,230 Subsequent to the acquisition on 19 December 2016, revenue and net income generated from the properties for the remainder of 2016 were not material. The Company did not incur any material acquisition costs related to the transaction. If both Eagle Ford acquisitions had been completed as of 1 January 2016, the Company’s pro forma revenue and loss before income taxes for the year ended 31 December 2016 would have been increased and reduced by $5.3 million and $1.2 million to $72.0 million and $(42.8) 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. Acquisitions in 2015 In August 2015, the Company completed its acquisition of New Standard Energy Ltd’s (“NSE”) U.S. (Eagle Ford) and Cooper Basin (Australia PEL570) assets for an aggregate purchase price of $16.4 million. The Eagle Ford assets acquired included approximately 5,500 net acres in Atascosa County, 7 gross producing wells and 2 wells that had been drilled, but not yet completed (one of which was subsequently completed by the Company). The Cooper Basin asset acquired included a 17.5% working interest in the Petroleum Exploration License (PEL) 570 concession, with drilling commitments of up to approximately AUD$10.6 million. Consideration paid for the assets included payment of $15.0 million to repay NSE’s outstanding debt and the issuance of 6 million fully paid ordinary Company shares, offset by acquired cash of $0.2 million. Approximately 1.5 million of the 6 million Company shares were held in escrow and are expected to be returned to the Company in 2017 in satisfaction of certain unresolved working capital adjustments and were not valued as part of consideration paid. |
DISPOSALS OF NON CURRENT ASSETS
DISPOSALS OF NON CURRENT ASSETS | 12 Months Ended |
Dec. 31, 2017 | |
DISPOSALS OF NON CURRENT ASSETS | |
DISPOSALS OF NON CURRENT ASSETS | NOTE 3 — DISPOSALS OF NON CURRENT ASSETS Disposals in 2017 In May 2017, the Company completed the sale of its interest in its Oklahoma oil and gas properties and certain other related assets and liabilities for a cash purchase price of $18.5 million, before closing adjustments. The sale was effective 1 August 2016 and resulted in a pre ‐ tax loss of $1.3 million. As part of the sale, the purchaser also assumed the Company’s restoration obligations associated with the properties of $0.9 million. The Oklahoma properties generated revenue, net of production taxes and operating expenses, of $1.4 million in 2017 prior to completion of the sale. Disposals in 2016 In December 2016, the Company divested an acreage block containing 3,336 gross (2,709 net) acres located in Atascosa County, Texas. The Eagle Ford acreage was undeveloped and outside the Company’s core development project area. Sundance received cash proceeds of $7.1 million for the acreage. No gain or loss was recognized in consolidated statement of profit and loss and other comprehensive income related to the sale. Disposals in 2015 There were no material disposals of non current assets during the year ended 31 December 2015. |
REVENUE
REVENUE | 12 Months Ended |
Dec. 31, 2017 | |
REVENUE. | |
REVENUE | NOTE 4 — REVENUE 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Oil revenue 89,136 57,296 82,949 Natural gas revenue 8,743 4,937 4,720 Natural gas liquid ("NGL") revenue 6,520 4,376 4,522 Total revenue 104,399 66,609 92,191 |
LEASE OPERATING EXPENSES
LEASE OPERATING EXPENSES | 12 Months Ended |
Dec. 31, 2017 | |
LEASE OPERATING EXPENSES | |
LEASE OPERATING EXPENSES | NOTE 5 — LEASE OPERATING EXPENSES 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Lease operating expense (17,127) (11,259) (16,667) Workover expense (5,289) (1,678) (1,788) Total lease operating expense (22,416) (12,937) (18,455) |
GENERAL AND ADMINISTRATIVE EXPE
GENERAL AND ADMINISTRATIVE EXPENSES | 12 Months Ended |
Dec. 31, 2017 | |
GENERAL AND ADMINISTRATIVE EXPENSES | |
GENERAL AND ADMINISTRATIVE EXPENSES | NOTE 6 — GENERAL AND ADMINISTRATIVE EXPENSES 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Employee benefits expense, including salaries and wages, net of capitalised overhead (4,088) (3,260) (4,849) Share-based payments expense (1) (1,868) (2,748) (4,100) Legal and other professional fees (6,330) (2,085) (3,347) Corporate fees (1,937) (1,762) (1,986) Rent (632) (669) (993) Regulatory expenses (314) (279) (203) Transaction related costs (2,118) (323) (540) Other expenses (1,058) (984) (1,158) Total general and administrative expenses (18,345) (12,110) (17,176) (1) Share based payment expense includes expense associated with restricted share units and deferred cash awards. See Note 33. The Company capitalised overhead costs, including salaries, wages benefits and consulting fees, directly attributable to the exploration, acquisition and development of oil and gas properties of $2.7 million, $2.1 million and $3.0 million for the years ended 31 December 2017, 2016 and 2015 respectively. |
INCOME TAX EXPENSE
INCOME TAX EXPENSE | 12 Months Ended |
Dec. 31, 2017 | |
INCOME TAX EXPENSE | |
INCOME TAX EXPENSE | NOTE 7 — INCOME TAX EXPENSE The Company assesses unrecognized deferred tax assets at the end of each reporting period. During the year ended 31 December 2017, it became probable that the Company would not have sufficient future taxable profit in the Australian jurisdiction to continue to recognize its deferred tax assets. Consequently, the Company has derecognized these assets during the period. The net impact of derecognizing these items resulted in income tax expense of $7.1 million with income tax expense of $0.2 million charged directly to equity. On December 22, 2017, the U.S. government enacted comprehensive tax legislation commonly referred to as the Tax Cut and Jobs Act of 2017 (“TCJA”). The passage of this legislation resulted in the change in the U.S. statutory rate from 35% to 21% beginning in January of 2018, the elimination of the corporate alternative minimum tax (“AMT”), the acceleration of depreciation for US tax purposes, limitations on deductibility of interest expense, the elimination of net operating loss carrybacks, and limitations on the use of future losses. In accordance with IAS 12 - Income Taxes , the impact of a change in tax law is recorded in the period of enactment or substantial enactment. Consequently, the Company has recorded a decrease to its deferred tax assets of $18.8 million with a corresponding net adjustment to its unrecognized tax assets for the year ended December 31, 2017. In addition to the elimination of the AMT, the TCJA allows for the refund of existing AMT credits beginning in tax years 2018 and continuing through tax year 2021. Consequently, the Company has reclassified its AMT credit of $4.7 million from an unrecognized tax asset to income tax receivable- noncurrent on the consolidated balance sheet, which will be claimed 50% on the Company’s tax filing for 2018, 25% on the filing for 2019, 12.5% on the filing for 2020, and 12.5% on the filing for 2021. This results in a current tax benefit of $4.7 million. The Company believes the effects of the change in tax law incorporated herein are substantially complete, but may be adjusted in future periods if additional information is obtained or further clarification or guidance is issued by regulatory authorities regarding this application of the law. As a result of other changes introduced by the TCJA, starting with compensation paid in 2018, Section 162(m) will limit us from deducting compensation, including performance-based compensation, in excess of $1 million paid to anyone who, starting in 2018, serves as the Chief Executive Officer or Chief Financial Officer, or who is among the three most highly compensated executive officers for any fiscal year. The only exception to this rule is for compensation that is paid pursuant to a binding contract in effect on November 2, 2017 that would have otherwise been deductible under the prior Section 162(m) rules. Accordingly, any compensation paid in the future pursuant to new compensation arrangements entered into after November 2, 2017, even if performance-based, will count towards the $1 million fiscal year deduction limit if paid to a covered executive. Additional information that may affect our income tax accounts and disclosures would include further clarification and guidance on how the Internal Revenue Service will implement tax reform, including guidance with respect to 100% bonus depreciation on self-constructed assets, further clarification and guidance on how state taxing authorities will implement tax reform and the related effect on our state income tax returns, completion of our 2017 tax return filings, and the potential for additional guidance from the IASB related to tax reform. The following is a summary of 2017, 2016 and 2015 income tax expense (benefit): 2017 2016 2015 Year ended 31 December US$’000 US$’00 US$’000 a) The components of income tax expense comprise: Current tax expense (benefit) (4,688) 1,563 (6,191) Deferred tax expense 2,815 142 (100,947) Total income tax expense (benefit) (1,873) 1,705 (107,138) b) The prima facie tax on loss from ordinary activities before income tax is reconciled to the income tax as follows: Loss before income tax (24,308) (43,989) (370,973) Prima facie tax expense at the Group’s statutory income tax rate of 30% (7,293) (13,197) (111,292) Increase (decrease) in tax expense resulting from: - Change in US Federal tax rate 18,821 — - Difference of tax rate in US controlled entities (53) (2,161) (20,447) - Impact of direct accounting from US controlled entities (1) (8) (98) (3,165) - Share-based compensation 781 539 747 - Other allowable items (83) 314 77 - Refundable AMT Credits (4,688) — — - Change in apportioned state tax rates in US controlled entities — — (84) - Change in unrecognized tax assets 9,471 16,308 27,026 - Change in unrecognized tax assets due to Tax Reform (18,821) — — Total income tax expense (benefit) (1,873) 1,705 (107,138) c) Unused tax losses and temporary differences for which no deferred tax asset has been recognised at 30% 36,672 46,022 29,714 d) Deferred tax charged directly to equity: - Equity raising costs 821 (986) — - Currency translation adjustment (952) 73 (362) (1) The Oklahoma US state tax jurisdiction computes income taxes on a direct accounting basis. Subsequent to 31 December 2017, the Company consolidated its two U.S. tax entities and will report as a single taxpayer in the U.S. |
OTHER INCOME (EXPENSES), NET
OTHER INCOME (EXPENSES), NET | 12 Months Ended |
Dec. 31, 2017 | |
OTHER INCOME (EXPENSES), NET | |
OTHER INCOME (EXPENSE), NET | NOTE 8 — OTHER INCOME (EXPENSE), NET 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Litigation settlements, net (1) (748) 1,200 — Insurance proceeds (2) — 2,375 — Escrow settlement from prior period property disposition (3) 1,000 — — Restructuring expenses (4) (56) (856) — Loss on foreign currency derivative — (390) — Write-off of unrecoverable cash call — — (1,621) Write-down of inventory to lower of cost or market — — (319) Other 261 (320) (300) Total other income, net 457 2,009 (2,240) (1) Litigation settlements, net recorded during the year ended 31 December 2017 includes the net impact of multiple favorable and unfavorable legal settlements, including an accrual for $1.0 million related to the Company’s 2013 sale of its non-operated North Dakota properties. In August 2015, the Buyer filed a lawsuit against the Company seeking payment for costs not included by the Buyer in the final post-closing settlement. In August 2017, a jury ruled in favor of the Buyer. The Company is currently appealing the decision, but has established a liability for such damages. During 2016, the Company was awarded a cash settlement of $1.2 million from litigation against a third party contractor for damages to a well that occurred in 2014. As part of the litigation settlement, the Company was also awarded $0.6 million for reimbursement of legal costs incurred (recorded to general and administrative expenses on the consolidated statement of profit or loss). (2) During 2016, the Company received insurance proceeds of $2.4 million related to a well control incident in 2014. (3) During 2017, the Company received a cash payout of $1.0 million from an escrow holding drilling commitment related funds related to properties sold by the Company in 2014. There had previously been uncertainty as to whether the drilling commitments would be met and to whom the funds would be paid to, and was therefore unrecognized in 2014. (4) In January 2016, the Company restructured its corporate organization and reduced its headcount by approximately 30% in order to reduce its cash operating costs in response to the lower oil price environment. Restructuring costs for the year ended 31 December 2016 included $0.4 million in employee severance costs and $0.5 million in office lease-related costs for certain office space that is expected to be no longer used as a result of office space consolidation. The office-lease-related costs represent the Company’s future obligations under the operating leases, net of anticipated sublease income. See also Note 23. |
KEY MANAGEMENT PERSONNEL COMPEN
KEY MANAGEMENT PERSONNEL COMPENSATION | 12 Months Ended |
Dec. 31, 2017 | |
KEY MANAGEMENT PERSONNEL COMPENSATION. | |
KEY MANAGEMENT PERSONNEL COMPENSATION | NOTE 9 — KEY MANAGEMENT PERSONNEL COMPENSATION a) The total remuneration paid to Directors and Key Management Personnel (“KMP”) of the Group during the year is as follows: 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Short term wages and benefits 1,444 1,298 1,467 Share-based payments (equity or cash settled) (1) 1,429 2,025 2,271 Post-employment benefit 53 49 52 2,926 3,372 3,790 (1) The 2014 short-term incentive bonus (“STI”) granted to KMP, excluding the Managing Director, was granted by the Board of Directors in 2015 and paid out in the form of RSUs, which vested immediately. The associated expense is included in 2015 share-based payments in the table above. The 2014 STI to the Managing Director was approved by shareholders in 2016 and paid out in the form of RSUs with immediate vesting. The associated expense is included in 2016 share based payments in the table above. b) Restricted Share Units Granted as Compensation RSUs awarded as compensation were 7,835,513 ($0.5 million fair value), 9,906,997 ($1.2 million fair value) and 7,426,596 ($3.8 million fair value) during the years ended 31 December 2017, 2016 and 2015, respectively, to KMP. The vesting provisions of the RSUs in effect during 2017 and 2016 vary and may vest immediately, based upon the passage of time or based on achievement of metrics related to the Company’s 3‑year absolute total shareholder (“ATSR”) or total shareholder return (“TSR”) as compared to its peer group. The details of the plan and TSR RSUs are described in more detail in Part I, Item 6. c) Deferred Cash Awards as Compensation Deferred cash awards vest based on the appreciation of the Company’s ordinary share volume weighted average price measured over a one to three year period. The liability and expense associated with such awards is measured at the end of each reporting period. Deferred cash awarded as compensation to KMP was $1,138,503 a nd $1,264,998 during the years ended 31 December 2017 and 2016, of which $379,501 and $632,499 was forfeited as the performance metrics associated with these awards were not achieved as at 31 December 2017. The deferred cash award is described in more detail in Part I, Item 6. |
AUDITORS' REMUNERATION
AUDITORS' REMUNERATION | 12 Months Ended |
Dec. 31, 2017 | |
AUDITORS’ REMUNERATION. | |
AUDITORS’ REMUNERATION | NOTE 10 — AUDITORS’ REMUNERATION 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Amounts paid or payable to the auditor for: Auditing or review of the financial report (1) 485 461 463 Professional services related to filing of various Forms with the US Securities and Exchange Commission — — 13 Taxation services provided by the practice of auditor — — 61 Total remuneration of the auditor 485 461 537 (1) The 2016 amount includes $0.4 million paid to the Company’s former auditor, Ernst & Young, who provided audit services for the year ended 31 December 2015. The Company paid $0.1 million in 2016 to Deloitte Touche Tohmatsu Limited as its auditor for the year ended 31 December 2016. |
EARNINGS (LOSS) PER SHARE (EPS)
EARNINGS (LOSS) PER SHARE (EPS) | 12 Months Ended |
Dec. 31, 2017 | |
EARNINGS (LOSS) PER SHARE (EPS) | |
EARNINGS (LOSS) PER SHARE (EPS) | NOTE 11 — EARNINGS (LOSS) PER SHARE (EPS) 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Loss for periods used to calculate basic and diluted EPS (22,435) (45,694) (263,835) Number Number Number of shares of shares of shares a) -Weighted average number of ordinary shares outstanding during the period used in calculation of basic EPS(1) 1,251,338,659 870,582,898 552,847,289 b) -Incremental shares related to options and restricted share units(2) — — — c) -Weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS 1,251,338,659 870,582,898 552,847,289 (1) Calculation excludes approximately 1.5 million ordinary shares held in escrow as at 31 December 2017, 2016 and 2015. The shares were issued as part of the NSE acquisition in 2015 and are expected to be returned to the Company in satisfaction of certain working capital adjustments. (2) Incremental shares related to restricted share units were excluded from 31 December 2017, 2016 and 2015 weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS as the outstanding shares would be anti-dilutive to the loss per share calculation for the period then ended. Subsequent to 31 December 2017, the Company issued 5,614,447,268 additional ordinary shares in connection with its $260 million equity-raise, described in Note 37. |
TRADE AND OTHER RECEIVABLES
TRADE AND OTHER RECEIVABLES | 12 Months Ended |
Dec. 31, 2017 | |
TRADE AND OTHER RECEIVABLES. | |
TRADE AND OTHER RECEIVABLES | NOTE 12 — TRADE AND OTHER RECEIVABLES 2017 2016 Year ended 31 December US$’000 US$’000 Oil, natural gas and NGL sales 2,604 8,201 Joint interest billing receivables 930 1,545 Commodity hedge contract receivables — 37 Other 432 3 Total trade and other receivables 3,966 9,786 Due to the short-term nature of trade and other receivables, their carrying amounts are assumed to approximate fair value. No material receivables were outside of normal trading terms as at 31 December 2017 and 2016. |
DERIVATIVE FINANCIAL INSTRUMENT
DERIVATIVE FINANCIAL INSTRUMENTS | 12 Months Ended |
Dec. 31, 2017 | |
DERIVATIVE FINANCIAL INSTRUMENTS | |
DERIVATIVE FINANCIAL INSTRUMENTS | NOTE 13 — DERIVATIVE FINANCIAL INSTRUMENTS 2017 2016 Year ended 31 December US$’000 US$’000 FINANCIAL ASSETS : Current Derivative financial instruments — commodity contracts 383 — Non-current Derivative financial instruments — commodity contracts 223 279 Total financial assets 606 279 FINANCIAL LIABILITIES : Current Derivative financial instruments — commodity contracts 5,618 4,579 Non-current Derivative financial instruments — commodity contracts 3,728 3,215 Total financial liabilities 9,346 7,794 |
ASSETS HELD FOR SALE
ASSETS HELD FOR SALE | 12 Months Ended |
Dec. 31, 2017 | |
ASSETS HELD FOR SALE | |
ASSETS HELD FOR SALE | NOTE 14 — ASSETS HELD FOR SALE The consolidated statement of financial position includes assets and liabilities held for sale, comprised of the following: 2017 2016 Year ended 31 December US$’000 US$’000 Eagle Ford - Dimmit County oil and gas assets 61,064 — Mississippian/Woodford oil and gas assets — 18,309 Total assets held for sale 61,064 18,309 Restoration provision associated with held for sale developed assets 1,064 941 Total liabilities related to assets held for sale 1,064 941 In June 2017, the Company committed to a plan to sell its assets located in Dimmit County, Texas. The assets to be sold include developed and production assets and exploration and evaluation expenditures. Sale of the Dimmit assets will provide additional capital for further development of the Company’s core McMullen and Atascosa County assets. The Company wrote-down the value of the Dimmit held for sale asset group as at 31 December 2017. See Note 19 for additional information. The Company’s Mississippian/Woodford assets were classified as held for sale as at 31 December 2016. The Company completed the sale of these assets in May 2017. Upon the completion of the sale of the Mississippian/Woodford assets, the Company’s lender reaffirmed the Company’s borrowing base. See Note 3 for additional information. |
FAIR VALUE MEASUREMENT
FAIR VALUE MEASUREMENT | 12 Months Ended |
Dec. 31, 2017 | |
FAIR VALUE MEASUREMENT | |
FAIR VALUE MEASUREMENT | NOTE 15 — FAIR VALUE MEASUREMENT The following table presents financial assets and liabilities measured at fair value in the consolidated statement of financial position in accordance with the fair value hierarchy. This hierarchy groups financial assets and liabilities into three levels based on the significance of inputs used in measuring the fair value of the financial assets and liabilities. The fair value hierarchy has the following levels: Level 1: quoted prices (unadjusted) in active markets for identical assets or liabilities; Level 2: inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (i.e. as prices) or indirectly (i.e. derived from prices); and 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 in the statement of financial position are grouped into the fair value hierarchy as follows: Consolidated 31 December 2017 (US$’000) Level 1 Level 2 Level 3 Total Assets measured at fair value Derivative commodity contracts — 606 — 606 Liabilities measured at fair value Derivative commodity contracts — (9,346) — (9,346) Net fair value — (8,740) — (8,740) Consolidated 31 December 2016 (US$’000) Level 1 Level 2 Level 3 Total Assets measured at fair value Derivative commodity contracts — 279 — 279 Liabilities measured at fair value Derivative commodity contracts — (7,794) — (7,794) Net fair value — (7,515) — (7,515) During the years ended 31 December 2017 and 2016, 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 a foreign currency contract. The Company utilises 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 at 31 December 2017, the Company had $125 million and $67 million of principal debt outstanding on its term loan and revolving facility, respectively. The estimated fair value of the Term Loan was approximately $119 million, based on indirect, observable inputs (Level 2) regarding interest rates available to the Company. The fair value of the term loan was determined by using a discounted cash flow model using a discount rate that reflects the Company’s assumed borrowing rate at the end of the reporting period. The Company’s revolving facility has a recorded value that approximates its fair value as its variable interest rate is tied to current market rates and the applicable margins of 2%‑3% approximate market rates. c) Other Financial Instruments The carrying amounts of cash, accounts receivable, accounts payable, accrued liabilities and the production prepayment approximate fair value due to their short-term nature. |
OTHER CURRENT ASSETS
OTHER CURRENT ASSETS | 12 Months Ended |
Dec. 31, 2017 | |
OTHER CURRENT ASSETS. | |
OTHER CURRENT ASSETS | NOTE 16 — OTHER CURRENT ASSETS 2017 2016 Year ended 31 December US$’000 US$’000 Oil inventory on hand, lesser of cost or net realizable value 908 517 Equipment inventory, lesser of cost or net realizable value 1,479 1,721 Prepaid expenses 915 1,205 Other 170 635 Total other current assets 3,472 4,078 |
DEVELOPMENT AND PRODUCTION ASSE
DEVELOPMENT AND PRODUCTION ASSETS | 12 Months Ended |
Dec. 31, 2017 | |
DEVELOPMENT AND PRODUCTION ASSETS. | |
DEVELOPMENT AND PRODUCTION ASSETS | NOTE 17 — DEVELOPMENT AND PRODUCTION ASSETS 2017 2016 Year ended 31 December US$’000 US$’000 Costs carried forward in respect of areas of interest in: Development and production assets, at cost: Producing assets 778,735 838,792 Wells-in-progress 954 4,997 Undeveloped assets 31,580 30,119 -Development and production assets, at cost: 811,269 873,908 Accumulated depletion (277,098) (258,613) Accumulated impairment (136,643) (258,277) Total development and production expenditure 397,528 357,018 Less amount classified as asset held for sale (1) (58,732) (18,309) Total Development and Production Expenditure, net of assets held for sale 338,796 338,709 a) Movements in carrying amounts: Development expenditure Balance at the beginning of the period 338,709 250,922 Amounts capitalised during the period 115,120 57,893 Fair value of assets acquired — 23,873 Revision to restoration provision 1,550 3,238 Depletion expense (57,851) (47,490) Impairment expense — (3,409) Development and production assets sold during the period — (5,030) Reclassifications from assets held for sale (2) — 77,021 Reclassifications to assets held for sale (1) (58,732) (18,309) Balance at end of period 338,796 338,709 (1) In 2017, the Company committed to a plan to sell its interests in Dimmit County, Texas. Balance reflects amount transferred to assets held for sale before impairment (see Note 19). (2) Borrowing costs relating to drilling of development wells that have been capitalized as part of oil and gas properties during the years ended 31 December 2017 and 2016 were $1.4 million and $1.1 million, respectively. The interest amounts capitalized as a percent of the total interest incurred for years ended 31 December 2017 and 2016 were 10.2% and 6.7%, respectively. |
EXPLORATION AND EVALUATION EXPE
EXPLORATION AND EVALUATION EXPENDITURE | 12 Months Ended |
Dec. 31, 2017 | |
EXPLORATION AND EVALUATION EXPENDITURE | |
EXPLORATION AND EVALUATION EXPENDITURE | NOTE 18 — EXPLORATION AND EVALUATION EXPENDITURE 2017 2016 Year ended 31 December US$’000 US$’000 Costs carried forward in respect of areas of interest in: Exploration and evaluation phase, at cost 185,819 176,550 Provision for impairment (143,093) (142,184) Total exploration and evaluation expenditures 42,726 34,366 Less amount classified as asset held for sale (1) (7,747) — Total Exploration and Evaluation Expenditure, net of assets held for sale 34,979 34,366 a) Movements in carrying amounts: Exploration and evaluation Balance at the beginning of the period 34,366 26,323 Amounts capitalised during the period 8,528 4,429 Exploration costs expensed — (30) Exploration tenements sold during the period — (2,096) Impairment expense (168) (7,871) Reclassifications from assets held for sale (2) — 13,611 Reclassifications to assets held for sale (1) (7,747) — Balance at end of period 34,979 34,366 (1) (2) The ultimate recoupment of costs carried forward for exploration phase is dependent on the successful development and commercial exploitation or sale of respective areas. |
IMPAIRMENT OF ASSETS
IMPAIRMENT OF ASSETS | 12 Months Ended |
Dec. 31, 2017 | |
IMPAIRMENT OF ASSETS | |
IMPAIRMENT OF ASSETS | NOTE 19 — IMPAIRMENT OF ASSETS Year-End 2017 Non-current oil and gas assets At 31 December 2017, the Group reassessed its non-current Eagle Ford assets for indicators of impairment or whether there was any indication that an impairment loss may no longer exist or may have decreased in accordance with the Group’s accounting policy. As at 31 December 2017, the Company’s market capitalisation was lower than the net book value of the Company’s net assets, which is deemed to be an indicator of impairment as described by IAS 36. As a result, the Company believes that under the prescribed accounting guidance there was indication that an impairment may exist related to its development and production assets and performed an impairment analysis. There was no indication of impairment or reversal of impairment related to its evaluation and expenditure assets. The Company estimated the VIU of the development and production assets using the income approach (Level 3 on fair value hierarchy) based on the estimated discounted future cash flows from the assets. The model took into account management’s best estimate for pricing and discount rates, as described below. In addition, the Company considered comparable market transactions to corroborate the estimated fair values. Future commodity price assumptions are based on the Group’s best estimates of future market prices with reference to bank price surveys, external market analysts’ forecasts, and forward curves. Future prices ($/bbl) used for the 31 December 2017 VIU calculation were as follows: 2023 and 2018 2019 2020 2021 2022 thereafter $ 60.00 $ 62.50 $ 65.00 $ 67.50 $ 70.00 $ 75.00 The pre-tax discount rates that have been applied to the development and production assets were 9.0% and 20.0% for proved developed producing and proved undeveloped properties, respectively. Management’s estimate of the recoverable amount using the VIU model as at 31 December 2017 exceeded the carrying cost of development and production and therefore no impairment was required. Dimmit County Assets Held For Sale In accordance with IFRS 5, assets held for sale are to be measured at the lower of FVLCS or the carrying value of the assets. To estimate FVLCS of the Dimmit County held for sale group at 31 December 2017, the Group utilized the income approach (Level 3 on fair value hierarchy) based on the estimated discounted future cash flows from the producing property and related exploration and evaluation assets. The model took into account management’s best estimate for pricing (described above) and discount rates, as described below. The Company is marketing the assets using internal personnel and therefore the cost of disposal is not expected to be material. The post-tax discount rates that have been applied to the Dimmit County held for sale asset group were 9.0% and 20.0% for proved developed producing and proved undeveloped properties, respectively. Management’s estimate of post-tax discount rates may be adjusted in the future based on the impact of TCJA, however it is too early for the Company to assess the impact on market participant behavior and assumptions because the enactment occurred near year-end and there have been limited comparable transactions subsequent to enactment. Based on recent comparable market transactions, the Company assigned no value to probable and possible reserves, consistent with the approach management believes a market participant would utilize. In addition, the Company corroborated the results of its discounted cash flow model with a market approach valuation which took into account market multiples derived from comparable market transactions of similar assets. The Company’s estimated that the FVLCS as at 31 December 2017 was $61 million, which resulted in impairment expense of $5.4 million. Year-End 2016 At 31 December 2016, the Group reassessed the carrying amount of its non-current assets for indicators of impairment or whether there is any indication that an impairment loss may no longer exist or may have decreased in accordance with the Group’s accounting policy. The Company determined there was no indication of impairment or impairment reversal for its Eagle Ford assets. The Company determined that there was an indication of impairment for its Mississippian/Woodward and Cooper Basin assets. Each of the Group’s development and production asset CGUs include all of its developed producing properties, shared infrastructure supporting its production and undeveloped acreage that the Group considers technically feasible and commercially viable. Mississippian/Woodward assets The Company actively marketed its Mississippian/Woodward assets in the second half of 2016. Based on the value of third-party bids and the execution of a purchase of sale agreement subsequent to 31 December 2016, the Company determined that there was an indication of impairment of both its exploration and evaluation assets and development and production assets. The Company recorded an impairment expense of $4.6 million, which was equal to the difference between the carrying value and the estimated sale proceeds, less selling costs. The Company recognized an additional loss on the sale of $1.3 million in 2017. Cooper Basin The Company has not received operational information indicating that the recovery of the Company’s carrying costs in the Cooper Basin is likely. As such, the Company wrote the asset down to nil and recorded an impairment expense of $6.7 million during the year ended 31 December 2016. The Company continued to incur and impair capital costs related to the Cooper Basin in 2017, totaling $0.2 million. Year-End 2015 At 31 December 2015, the Group determined that due to the decline in the oil pricing environment, that there was an indication of impairment for all of its exploration and evaluation expenditures and its development and production assets. Estimates of recoverable amounts are based on the higher of an asset’s value-in-use or fair value less costs to sell (level 3 fair value hierarchy), using a discounted cash flow method, and are most sensitive to the key assumptions such as pricing, discount rates, and reserve risk factors. For its development and production assets, the Group has used the FVLCS calculation whereby future cash flows are based on estimates of hydrocarbon reserves in addition to other relevant factors such as value attributable to additional reserves based on production plans. For its exploration and evaluation expenditures, the Group has used the FVLCS calculation determined by the probability weighted combination of a discounted cash flow method and market transactions for comparable undeveloped acreage. Estimates of future commodity prices are based on the Group’s best estimates of future market prices with reference to bank price surveys, external market analysts’ forecasts, and forward curves. Future prices ($/bbl) used for the 31 December 2015 FVLCS calculation were as follows: 2019 and 2016 2017 2018 thereafter $ 40.00 $ 50.00 $ 60.00 $ 70.00 As at 31 December 2015, the post-tax discount rate that has been applied to the above non-current assets were 9.0% and 10.0% for proved developed producing and proved undeveloped properties, respectively. As at 31 December 2015, the Group also applied further risk-adjustments appropriate for risks associated with its proved undeveloped reserves using a risk-adjustment rate of 20% based on the risk associated with the undeveloped reserve category. Recoverable amounts and resulting impairment expense recognized in conjunction with the Company’s impairment analysis as at 31 December 2017, 2017 and 2015 are presented in the table below. Recoverable 31 December 2017 Carrying costs amount Impairment (1) Cash-generating unit US$’000 US$’000 US$’000 Assets held for sale - Dimmit County 66,479 61,064 5,415 31 December 2016 Cash-generating unit (2) Exploration and evaluation expenditures: Mississippian/Woodford 1,183 — 1,183 Cooper Basin 6,688 — 6,688 Total exploration and evaluation 7,871 — 7,871 Development and production assets: Mississippian/Woodford 21,693 18,309 3,384 Total development and production assets 21,693 18,309 3,384 31 December 2015 Cash-generating unit Exploration and evaluation expenditures: Eagle Ford 151,171 33,511 (117,660) Mississippian/Woodford 5,164 1,190 (3,974) Cooper Basin 7,436 5,234 (2,202) Total exploration and evaluation 163,771 39,935 (123,836) Development and production assets: Eagle Ford 431,796 308,083 (123,713) Mississippian/Woodford 77,940 19,859 (58,081) Total development and production assets 509,736 327,942 (181,794) (1) Total impairment expense for the year ended 31 December 2017 also included $0.2 million related to additional costs incurred at the Cooper Basin, which was fully impaired in 2016. (2) Total impairment expense for the year ended 31 December 2016 was $11.3 million, which was net of an adjustment to 2015 impairment expense of $1.1 million related to a vendor discount for well completion services obtained subsequent to the filing of the Company’s 2015 annual report. Total impairment expense was $10.2 million. (3) The 31 December 2015 table reflects the year-end impairment analysis. The Company also recorded impairment expense related to its Mississippian/Woodford development and production assets of $2.6 million and its exploration and evaluation assets of $13.4 million during the first half of the year ended 31 December 2015. Any further adverse changes in any of the key assumptions may result in future impairments. |
PROPERTY AND EQUIPMENT
PROPERTY AND EQUIPMENT | 12 Months Ended |
Dec. 31, 2017 | |
PROPERTY AND EQUIPMENT. | |
PROPERTY AND EQUIPMENT | NOTE 20 — PROPERTY AND EQUIPMENT 2017 2016 Year ended 31 December US$’000 US$’000 Property and equipment, at cost 3,628 3,146 Accumulated depreciation (2,382) (1,935) Total Property and Equipment 1,246 1,211 a) Movements in carrying amounts: Balance at the beginning of the period 1,211 1,382 Amounts capitalized during the period 659 355 Amounts disposed of during the period (122) (151) Depreciation expense (502) (375) Balance at end of period 1,246 1,211 |
TRADE AND OTHER PAYABLES AND AC
TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES | 12 Months Ended |
Dec. 31, 2017 | |
TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES | |
TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES | NOTE 21 — TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES 2017 2016 Year ended 31 December US$’000 US$’000 Oil and natural gas property and operating related 40,001 18,588 Administrative expenses, including salaries and wages 4,494 2,225 Accrued interest payable 3,057 2,761 Commodity derivative contract payables 550 — Total trade, other payables and accrued expenses 48,102 23,574 |
PRODUCTION PREPAYMENT
PRODUCTION PREPAYMENT | 12 Months Ended |
Dec. 31, 2017 | |
PRODUCTION PREPAYMENT | |
PRODUCTION PREPAYMENT | NOTE 22 — PRODUCTION PREPAYMENT On 31 July 2017, the Company entered into an agreement with Vitol Inc. (“Vitol”), the Company’s oil purchaser, to provide a revenue advance to the Company of $30 million to be repaid through delivery of the Company’s oil production through full repayment of the $30 million. The advance bears interest at rate of 10% per annum. The Company began repaying the advance in October 2017 at a rate of $20 per gross barrel produced by Sundance operated wells through 31 December 2017. The rate of repayment increased to $25 per gross barrel beginning 1 January 2018 through full repayment. Under the agreement, the Company’s oil production continues to be sold at the prevailing contract rates, with the Company retaining any differential between market and the aforementioned per barrel repayment amount. If the Company has not fully repaid the liability by 31 March 2018, the repayment rate will increase to $40 per gross barrel produced. The Company expects the repay the liability in full in April 2018 upon completion of the acquisition, equity raise and debt refinancing, described in more detail in Note 39. This agreement provided near-term liquidity to the Company to complete its 2017 development plan. As at 31 December 2017, the balance outstanding under the agreement was $18.2 million. |
OTHER PROVISIONS
OTHER PROVISIONS | 12 Months Ended |
Dec. 31, 2017 | |
OTHER PROVISIONS. | |
OTHER PROVISIONS | NOTE 23 — OTHER PROVISIONS 2017 2016 Year ended 31 December US$’000 US$’000 Balance at the beginning of the period (1) 6,025 — New provisions — 6,025 Changes in estimates (747) — Settlements (1,932) — Unwinding of discount 73 — Reclassification from provisions to accrued liabilities (103) — Balance at end of period (1) 3,316 6,025 (1) During 2016, the Company entered into an agreement with Schlumberger Limited (“Schlumberger”) to re ‐ fracture five Eagle Ford wells. Under the terms of the agreement, Schlumberger will be paid for the services, plus a premium (if applicable), from the incremental production generated by the re ‐ fractured wells above the forecasted base production prior to the re ‐ fracture work. The term of the agreement is five years, expiring in 2021. The estimate of the payout amount requires judgements regarding future production, pricing, operating costs and discount rates. Also during 2016, the Company recognized a provision related to certain office space that was to no longer be used as a result of office space consolidation. The office ‐ lease ‐ related costs represented the Company's estimate of future obligations under the operating leases, net of anticipated sublease income. The Company entered into an agreement to sublease the office space in 2017 and at 31 December 2017, the liability was no longer considered a provision. The remaining liability was reclassified into accrued expenses on the consolidated statement of financial position. |
CREDIT FACILITIES
CREDIT FACILITIES | 12 Months Ended |
Dec. 31, 2017 | |
CREDIT FACILITIES. | |
CREDIT FACILITIES | NOTE 24 — CREDIT FACILITIES 2017 2016 US$'000 US$'000 Revolving Facility 67,000 66,750 Term Loan 125,000 125,000 Total Credit Facilities 192,000 191,750 Deferred financing fees, net of accumulated amortisation (2,690) (3,501) Total credit facilities, net of deferred financing fees 189,310 188,249 On May 14, 2015, Sundance Energy Australia Limited and Sundance Energy, Inc. entered into a Credit Agreement (the “Credit Agreement”) with Morgan Stanley Energy Capital, Inc., as administrative agent (“Agent”) and the lenders from time to time party thereto, which provides for a $300 million senior secured revolving credit facility (the “Revolving Facility”) and a term loan of $125 million (the “Term Loan”). The Credit Agreement is 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 borrowing base was reaffirmed at $67 million in the fourth quarter of 2017. The Revolving Facility has a five year term (matures in May 2020) and the Term Loan has a 5 ½ year term (matures in November 2020). 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. Interest on the Revolving Facility accrues at a rate equal to LIBOR, plus a margin ranging from 2% to 3% depending on the level of funds borrowed. Interest on the Term Loan accrues at a rate equal to the greater of (i) LIBOR, plus 7% or (ii) 8%. The Company is required under our Credit Agreement to maintain the following financial ratios: · a minimum current ratio, consisting of consolidated current assets including undrawn borrowing capacity to consolidated current liabilities, 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 Revolving Facility Debt to adjusted consolidated EBITDAX (as defined in the Credit Facility), of not greater than 4.0 to 1.0 as of the last day of any fiscal quarter; · a minimum interest coverage ratio, consisting of EBITDAX to Consolidated Interest Expense (as defined in the Credit Facility), of not less than 2.0 to 1.0 as of the last day of any fiscal quarter; and · An asset coverage ratio, consisting of PV9% to Total Debt (as defined in the Credit Facility), of not less than 1.50 to 1.0. As at 31 December 2017, the Company was in compliance with all restrictive financial and other covenants under the Credit Agreement. The Company refinanced its Credit Facilities in April 2018 upon completion of its acquisition and equity raise described in more detail in Note 39. |
RESTORATION PROVISION
RESTORATION PROVISION | 12 Months Ended |
Dec. 31, 2017 | |
RESTORATION PROVISION. | |
RESTORATION PROVISION | NOTE 25 — RESTORATION PROVISION The restoration provision represents the Company’s best estimate of the present value of restoration costs relating to its oil and natural gas interests, which are expected to be incurred through 2047. Assumptions, based on the current economic environment, have been made which management believes are a reasonable basis upon which to estimate the future liability. The estimate of future removal costs requires management to make significant judgments regarding removal date or well lives, the extent of restoration activities required, discount and inflation rates. These estimates are reviewed regularly to take into account any material changes to the assumptions. However, actual restoration costs will reflect market conditions at the relevant time. Furthermore, the timing of restoration is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend on future oil and natural gas prices, which are inherently uncertain. 2017 2016 Year ended 31 December US$’000 US$’000 Balance at the beginning of the period 7,072 3,088 New provisions 938 305 Changes in estimates 663 2,956 Disposals and settlements (256) (114) New provisions assumed from acquisition — 894 Unwinding of discount 214 140 Reclassification from liabilities related to assets held for sale — 744 Reclassification to liabilities related to assets held for sale (1,064) (941) Balance at end of period 7,567 7,072 (1) |
DEFERRED TAX ASSETS AND LIABILI
DEFERRED TAX ASSETS AND LIABILITIES | 12 Months Ended |
Dec. 31, 2017 | |
DEFERRED TAX ASSETS AND LIABILITIES. | |
DEFERRED TAX ASSETS AND LIABILITIES | NOTE 26 — DEFERRED TAX ASSETS AND LIABILITIES Deferred tax assets and liabilities are attributable to the following: 2017 2016 Year ended 31 December US$’000 US$’000 Net deferred tax assets: Share issuance costs — 1,534 Net operating loss carried forward — 2,636 Accrued interest — (2,756) Derivatives 1,884 — Development and production expenditure — 1,269 Other 111 Total net deferred tax assets 1,995 2,683 Deferred tax liabilities: Development and production expenditure (25,971) (10,654) Offset by deferred tax assets with legally enforceable right of set-off: Net operating loss carried forward 23,976 7,218 Accrued interest — 3,436 Total net deferred tax liabilities (1,995) — |
ISSUED CAPITAL
ISSUED CAPITAL | 12 Months Ended |
Dec. 31, 2017 | |
ISSUED CAPITAL. | |
ISSUED CAPITAL | NOTE 27 — ISSUED CAPITAL Total ordinary shares issued and outstanding at each period end are fully paid. All shares issued are authorized. Shares have no par value. Number of Shares a) Ordinary Shares Total shares issued and outstanding at 31 December 2015 559,103,562 Shares issued during the year (1) 690,248,055 Total shares issued and outstanding at 31 December 2016 1,249,351,617 Shares issued during the year 3,897,911 Total shares issued and outstanding at 31 December 2017 1,253,249,528 (1) Includes 1.5 million shares held in escrow related to the Company’s acquisition of NSE. Ordinary shares participate in dividends and the proceeds on winding up of the Parent Company in proportion to the number of shares held. At shareholders’ meetings each ordinary share is entitled to one vote when a poll is called, otherwise each shareholder has one vote on a show of hands. 2017 2016 Year ended 31 December US$’000 US$’000 b) Issued Capital Beginning of the period 373,585 308,429 Shares issued in connection with: Share consideration paid in business combination — — Shares issued in conjunction with private placement (1) — 67,499 Total shares issued during the period — 67,499 Cost of capital raising during the period, net of tax benefit — (2,343) Derecognition of deferred tax asset (see note 7) (821) — Closing balance at end of period 372,764 373,585 (1) In 2016, the Company completed a 3‑tranche private placement of 685 million ordinary shares to professional and sophisticated investors for net proceeds of $64.2 million. The Company also recognized a tax benefit on the cost of capital of $1.0 million. c) Restricted Share Units on Issue Details of the restricted share units issued or issuable as at 31 December: 2017 2016 Grant Date No. of RSUs No. of RSUs 15 April 2014 — 393,311 30 May 2014 — 167,997 28 May 2015 515,037 1,030,075 28 May 2015 (1) 1,545,113 1,545,113 24 June 2015 1,122,571 2,382,229 24 June 2015 (1) 2,267,879 2,267,879 1 August 2015 107,000 214,000 15 March 2016 (2) 6,824,951 6,824,950 27 May 2016 (2) 4,342,331 4,342,331 29 June 2016 (2) 1,633,763 3,614,316 15 August 2016 (2) — 800,000 15 August 2016 — 200,000 3 January 2017 187,500 — 17 February 2017 (2) 6,627,667 — 25 May 2017 (2) 3,724,191 — 23 October 2017 (2) 745,000 — 23 October 2017 1,500,000 — 29 December 2017 2,660,358 — Total RSUs outstanding 33,803,361 23,782,201 (1) (2) d) Capital Management Management controls the capital of the Group in order to maintain an appropriate debt to equity ratio, provide the shareholders with adequate returns and ensure that the Group can fund its operations and continue as a going concern. The Group’s debt and capital includes ordinary share capital and financial liabilities, supported by financial assets. Other than the covenants described in Note 24, the Group has no externally imposed capital requirements. Management effectively manages the Group’s capital by assessing the Group’s financial risks and adjusting its capital structure in response to changes in these risks and in the market. These responses include the management of debt levels, distributions to shareholders and shareholder issues. There have been no changes in the strategy adopted by management to control the capital of the Group since the prior period. The strategy is to ensure that any significant increases to the Group’s debt or equity through additional draws or raises have minimal impact to its gearing ratio. As at 31 December 2017 and 2016, the Company had $192 million outstanding debt. |
RESERVES
RESERVES | 12 Months Ended |
Dec. 31, 2017 | |
RESERVES | |
RESERVES | NOTE 28 — RESERVES a) Share-Based Payments Reserve The share based payments reserve records items recognised as expenses on valuation of employee share options and restricted share units. b) Foreign Currency Translation Reserve The foreign currency translation reserve records exchange differences arising on translation of the Parent Company. |
CAPITAL AND OTHER EXPENDITURE C
CAPITAL AND OTHER EXPENDITURE COMMITMENTS | 12 Months Ended |
Dec. 31, 2017 | |
CAPITAL AND OTHER EXPENDITURE COMMITMENTS | |
CAPITAL AND OTHER EXPENDITURE COMMITMENTS | NOTE 29 — CAPITAL AND OTHER EXPENDITURE COMMITMENTS Capital commitments relating to tenements As at 31 December 2017, all of the Company’s core exploration and evaluation and development and production assets are located in Texas. The Company has an interest in a non-core exploration and evaluation license located in Australia. The mineral leases in the exploration prospects in the US have primary terms ranging from 3 years to 5 years and generally have no specific capital expenditure requirements. However, mineral leases that are not successfully drilled and included within a spacing unit for a producing well within the primary term will expire at the end of the primary term unless re-leased. The Company is committed to fund exploratory drilling in the Cooper Basin (Australia) of up to approximately A$10.6 million through 2019, of which A$6.2 million (US$4.8 million) had been incurred as at 31 December 2017. The following tables summarize the Group’s contractual commitments not provided for in the consolidated statements of financial position: Total Less than More than As at 31 December 2017 US$’000 1 year 1 — 5 years 5 years Cooper Basin capital commitments (1) 3,490 1,745 1,745 — Operating lease commitments (2) 2,446 1,050 1,396 — Employment commitments (3) 370 370 — — Total expenditure commitments 6,306 3,165 3,141 — As at 31 December 2016 Total US$’000 Less than 1 year 1 — 5 years More than 5 years Cooper Basin capital commitments (1) 3,373 1,687 1,686 — Drilling rig commitments (4) 1,085 1,085 — — Operating lease commitments (2) 4,123 1,353 2,267 503 Employment commitments (3) 740 370 370 — Total expenditure commitments 9,321 4,495 4,323 503 (1) (2) (3) (4) |
CONTINGENT ASSETS AND LIABILITI
CONTINGENT ASSETS AND LIABILITIES | 12 Months Ended |
Dec. 31, 2017 | |
CONTINGENT ASSETS AND LIABILITIES | |
CONTINGENT ASSETS AND LIABILITIES | NOTE 30 — CONTINGENT ASSETS AND LIABILITIES The Company is involved in various legal proceedings in the ordinary course of business. The Company 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 the Company’s management that as of the date of this report, it is not probable that these claims and litigation involving the Company 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 at December 31, 2017. At the date of signing this report, the Group is not aware of any other contingent assets or liabilities that should be recognized or disclosed in accordance with AASB 137/IAS 37 — Provisions, Contingent Liabilities and Contingent Assets. |
OPERATING SEGMENTS
OPERATING SEGMENTS | 12 Months Ended |
Dec. 31, 2017 | |
OPERATING SEGMENTS | |
OPERATING SEGMENTS | NOTE 31 — OPERATING SEGMENTS The Company’s strategic focus is the exploration, development and production of large, repeatable onshore resource plays in North America. All of the basins and/or formations in which the Company operates in North America have common operational characteristics, challenges and economic characteristics. As such, Management has determined, based upon the reports reviewed and used to make strategic decisions by the Chief Operating Decision Maker (“CODM”), whom is the Company’s Managing Director and Chief Executive Officer, that the Company has one reportable segment being oil and natural gas exploration and production in North America. For the years ended 31 December 2017, 2016 and 2015, all statement of profit or loss and other comprehensive income activity was attributed to its reportable segment with the exception of $0.2 million, $6.7 million and $2.2 million of pre-tax impairment expense, which related to the impairment of its Cooper Basin assets in Australia, respectively. Geographic Information The operations of the Group are located in two geographic locations, North America and Australia. The Company’s Australian assets (Cooper Basin) were acquired in 2015 from NSE and the Company intends to sell these assets as they fall outside the Company’s strategic focus. All revenue is generated from sales to customers located in North America. As at 31 December 2017 and 2016, the carrying value of the assets held in Australia was nil. Revenue from two major customers exceeded 10 percent of Group consolidated revenue for the year ended 31 December 2017 and accounted for 50 and 34 percent, respectively (2016: two major customers accounting for 69 and 12 percent, respectively and 2015: three major customers accounted for 30, 29 and 22 percent, respectively) of our consolidated oil, natural gas and NGL revenues. |
CASH FLOW INFORMATION
CASH FLOW INFORMATION | 12 Months Ended |
Dec. 31, 2017 | |
CASH FLOW INFORMATION | |
CASH FLOW INFORMATION | NOTE 32 — CASH FLOW INFORMATION 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 a) Reconciliation of cash flows from operations with income from ordinary activities after income tax Loss from ordinary activities after income tax (22,435) (45,694) (263,835) Adjustments to reconcile net profit to net operating cash flows: Depreciation and amortisation expense 58,361 48,147 94,584 Share-based compensation 2,076 2,524 4,100 Unrealised losses on derivatives 1,224 21,433 (3,444) Net loss (gain) on sale of non-current assets 1,461 — (790) Decrease in fair value of securities at fair value through the profit and loss — — 90 Impairment of development and production assets 5,583 10,203 321,918 Unsuccessful exploration and evaluation expense — 30 — Loss on debt extinguishment — — 1,151 Add: Interest expense and financing costs (disclosed in investing and financing activities) 12,676 12,219 9,418 Recognition (derecognition) of deferred tax assets on items directly within equity (821) 986 — Less: Gain from escrow settlement, insurance proceeds and litigation settlements (disclosed in investing activities) (2,200) (3,603) — Less: Loss on foreign currency derivative (disclosed in financing activities) — 390 — Other 541 21 2,240 Changes in assets and liabilities: - Decrease (increase) in current and deferred income tax 2,888 (826) (100,583) - Decrease (increase) in other current assets 72 (511) 2,742 - Decrease in trade and other receivables 5,241 2,009 7,007 - Increase (decrease) in trade and other payables 9,633 (5,080) (2,177) - Decrease in tax receivable 476 412 (6,522) - Decrease in non-current liability — — (1,430) Net cash provided by operating activities 74,776 42,660 64,469 b) Non Cash Financing and Investing Activities - The Company had non-cash additions to oil and natural gas properties of $27,726, $13,161 and $22,559 included in current liabilities at 31 December 2017, 2016 and 2015, respectively. - During the year ended 31 December 2015, the net gain on sale of properties primarily related to an ad valorem tax true-up related to properties sold in 2014. |
SHARE BASED PAYMENTS
SHARE BASED PAYMENTS | 12 Months Ended |
Dec. 31, 2017 | |
SHARE BASED PAYMENTS | |
SHARE BASED PAYMENTS | NOTE 33 — SHARE BASED PAYMENTS The Company recognized share based compensation expense of $1.9 million, $2.7 million and $4.1 million for the years ended 31 December 2017, 2016 and 2015, respectively, comprised of RSUs (equity-settled) and deferred cash awards (cash-settled) and options. Restricted Share Units During the years ended 31 December 2017, 2016 and 2015, the Board of Directors awarded 15,757,216, 16,992,192 and 13,322,262 RSUs, respectively, to certain employees (of which 3,724,191, 5,113,281 and 3,090,000, respectively, granted to the Company’s Managing Director were approved by shareholders). These awards were made in accordance with the long-term equity component of the Company’s incentive compensation plan, the details of which are described in more detail in the Remuneration Report of the Directors’ Report. The fair value calculation methodology is described in Note 1. RSU expense totaled $2.1 million, $2.5 million and $4.1 million for the years ended 31 December 2017, 2016 and 2015, respectively. This information is summarised for the Group for the years ended 31 December 2017, 2016 and 2015, respectively, below: Weighted Average Fair Number Value at Measurement of RSUs Date A$ Outstanding at 31 December 2014 2,964,177 0.93 Issued or Issuable 13,322,262 0.53 Converted to ordinary shares (3,805,789) 0.63 Forfeited (46,312) 0.93 Outstanding at 31 December 2015 12,434,338 0.55 Issued or Issuable (1) 18,267,192 0.18 Converted to ordinary shares (5,501,538) 0.54 Forfeited (1,417,791) 0.59 Outstanding at 31 December 2016 23,782,201 0.34 Issued or Issuable 15,757,216 0.09 Converted to ordinary shares (3,897,911) 0.43 Forfeited (1,838,145) 0.15 Outstanding at 31 December 2017 33,803,361 0.22 (1) Includes 1,275,000 of RSUs formally issued on the ASX in 2016 in conjunction with a 2015 option conversion. The following tables summarise the RSUs issued and their related grant date, fair value and vesting conditions: RSUs awarded during the year ended 31 December 2017: Fair Value at Measurement Date Grant Date Number of RSUs (Per RSU in US$) Vesting Conditions 3 January 2017 250,000 $ 0.22 25% after 90 days; then 25% on 3 January 2018, 2019 and 2020 9 January 2017 250,000 $ 0.24 25% after 90 days; then 25% on 9 January 2018, 2019 and 2020 2 February 2017 6,627,667 $ 0.12 0 % - 150% based on 3 year ATSR 25 May 2017 3,724,191 $ 0.05 0 % - 150% based on 3 year ATSR 23 October 2017 745,000 $ 0.03 0 % - 150% based on 3 year ATSR 23 October 2017 1,500,000 $ 0.05 25% after 90 days; then 25% on 23 October 2018, 2019 and 2020 29 December 2017 2,660,358 $ 0.07 33 % on 31 January 2018, 2019 and 2020 15,757,216 RSUs awarded during the year ended 31 December 2016: Fair Value at Measurement Date Grant Date Number of RSUs (Per RSU in US$) Vesting Conditions 15 March 2016 6,824,950 $ 0.15 0 % - 133% based on 3 year ATSR 27 May 2016 4,342,331 $ 0.10 0 % - 133% based on 3 year ATSR 27 May 2016 770,950 $ 0.12 100 % vested immediately 29 June 2016 3,853,961 $ 0.08 33 % on 1 January 2017, 2018 and 2019 15 August 2016 400,000 $ 0.11 50 % on 13 November 2016 and 50% on 11 February 2017 15 August 2016 800,000 $ 0.11 0 % - 133% based on 3 year ATSR 16,992,192 RSUs awarded during the year ended 31 December 2015: Fair Value at Measurement Date Grant Date Number of RSUs (Per RSU in US$) Vesting Conditions 27 April 2015 $ 25 % on 27 April 2016, 2017, 2018 and 2019 28 May 2015 1,545,113 $ 33 % on 31 January 2016, 2017 and 2018 28 May 2015 1,545,113 $ 0% - 200% based on 3 year total shareholder return as compared to peers 24 June 2015 4,267,002 $ 33 % on 31 January 2016, 2017 and 2018 24 June 2015 2,815,681 $ 0% - 200% based on 3 year total shareholder return as compared to peers 24 June 2015 2,809,479 $ 100 % vested upon issuance 1 September 2015 321,000 $ 33 % on 31 January 2016, 2017 and 2018 13,332,262 Upon vesting, and after a certain administrative period, the RSUs are converted to ordinary shares of the Company. Once converted to ordinary shares, the RSUs are no longer restricted. For the years ended 31 December 2017, 2016 and 2015 the weighted average price of the RSUs at the date of conversion was A$0.19, A$0.11, and A$0.52 per share, respectively. At 31 December 2017, the weighted average remaining contractual life of the RSUs was 1.4 years. Deferred Cash Awards During the years ended 31 December 2017 and 2016, the Board of Directors awarded $2.0 million and $2.1 million of deferred cash awards to certain employees. Under the deferred cash plan, awards may vest between 0%‑300%, earned through appreciation in the price of Sundance’s ordinary shares over a one to three year period. The details of the award is described in more detail in the Remuneration Report of the Directors’ Report and the fair value calculation methodology is described in Note 1. The Company recorded income of $(0.2) million and expense of $0.2 million for the years ended 31 December 2017 and 2016, respectively. The estimated weighted average fair value of each one dollar unit of deferred cash awards as at 31 December 2017 was $0.03, resulting in a total liability of $16 thousand. Amount of Deferred Cash Awards Outstanding at 31 December 2014 — Granted — Vested and paid in cash — Forfeited — Outstanding at 31 December 2015 — Granted 2,079,879 Vested and paid in cash — Forfeited (31,681) Outstanding at 31 December 2016 2,048,198 Granted 1,998,675 Vested and paid in cash — Forfeited (1,744,228) Outstanding at 31 December 2017 2,302,645 |
RELATED PARTY TRANSACTIONS
RELATED PARTY TRANSACTIONS | 12 Months Ended |
Dec. 31, 2017 | |
RELATED PARTY TRANSACTIONS | |
RELATED PARTY TRANSACTIONS | NOTE 34 — RELATED PARTY TRANSACTIONS There were no material related party transactions for the years ended 31 December 2017, 2016 and 2015. |
FINANCIAL RISK MANAGEMENT
FINANCIAL RISK MANAGEMENT | 12 Months Ended |
Dec. 31, 2017 | |
FINANCIAL RISK MANAGEMENT | |
FINANCIAL RISK MANAGEMENT | NOTE 35 — FINANCIAL RISK MANAGEMENT a) Financial Risk Management Policies The Group is exposed to a variety of financial market risks including interest rate, commodity prices, foreign exchange and liquidity risk. The Group’s risk management strategy focuses on the volatility of commodity markets and protecting cash flow in the event of declines in commodity pricing. The Group has historically used derivative financial instruments to hedge exposure to fluctuations in commodity prices, and at times, interest rates and foreign currency transactions. The Group’s financial instruments consist mainly of deposits with banks, accounts receivable, derivative financial instruments, credit facility, and payables. The main purpose of non-derivative financial instruments is to providing funding for the Group operations. i) Treasury Risk Management Financial risk management is carried out by Management. The Board sets financial risk management policies and procedures by which Management are to adhere. Management identifies and evaluates all financial risks and enters into financial risk instruments to mitigate these risk exposures in accordance with the policies and procedures outlined by the Board. ii) Financial Risk Exposure and Management The Group’s interest rate risk arises from its borrowings. Interest rate risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The Group’s exposure to the risk of changes in market interest rates relates primarily to the Group’s long-term debt obligations with floating interest rates. iii) Commodity Price Risk Exposure and Management The Board actively reviews oil and natural gas hedging on a monthly basis. Reports providing detailed analysis of the Group’s hedging activity are continually monitored against Group policy. The Group sells its oil on market using NYMEX West Texas Intermediary (“WTI”) and Louisiana Light Sweet (“LLS”) market spot rates reduced for basis differentials in the basins from which the Company produces. Gas is sold using Henry Hub (“HH”) and Houston Ship Channel (“HSC”) market spot prices. Forward contracts are used by the Group to manage its forward commodity price risk exposure. The Group’s policy is to hedge at least 50% of its proved developed reserves through 2019 and for a rolling 36 month period thereafter, as required by its Credit Agreement. The Group has not elected to utilise hedge accounting treatment and changes in fair value are recognised in the statement of profit or loss and other comprehensive income. A summary of the Company’s outstanding derivative positions as at 31 December 2017 is below: Oil Derivatives (WTI/LLS) Weighted Average (1) Year Units (Bbls) Floor Ceiling 2018 891,000 $ 50.40 $ 56.86 2019 828,000 $ 50.56 $ 53.49 2020 108,000 $ 47.05 $ 52.50 Total 1,827,000 $ 50.28 $ 55.07 Gas Derivatives (HH/HSC) Weighted Average (1) Year Units (Mcf) Floor Ceiling 2018 2,106,000 $ 2.92 $ 3.24 2019 1,212,000 $ 2.78 $ 3.47 2020 216,000 $ 2.54 $ 2.93 Total 3,534,000 $ 2.85 $ 3.30 (1) b) Net Fair Value of Financial Assets and Liabilities The net fair value of cash and cash equivalent and non-interest bearing monetary financial assets and financial liabilities of the consolidated entity approximate their carrying value. The net fair value of other monetary financial assets and financial liabilities is based on discounting future cash flows by the current interest rates for assets and liabilities with similar risk profiles. Other than the Term Loan, the balances are not materially different from those disclosed in the consolidated statement of financial position of the Group. c) Credit Risk Credit risk for the Group arises from investments in cash and cash equivalents, derivative financial instruments and deposits with banks and financial institutions, as well as credit exposures to customers and joint-interest partners including outstanding receivables and committed transactions, and represents the potential financial loss if counterparties fail to perform as contracted. The Group trades only with recognised, creditworthy third parties. The maximum exposure to credit risk, excluding the value of any collateral or other security, is the carrying amount, net of any impairment of those assets, as disclosed in the balance sheet and notes to the financial statements. Receivable balances are monitored on an ongoing basis at the individual customer level. At 31 December 2017, the Group had three customers that owed the Group approximately $1.0 million, $0.8 million and $0.6 million which accounted for approximately 39%, 29% and 22% of total accrued revenue receivables, respectively. In the event that the customer to the Company’s largest outstanding receivable defaults, the Company could draw upon a letter of credit in place for the Company’s benefit. For joint interest billing receivables, if payment is not made, the Group can withhold future payments of revenue, as such, there is minimal to no credit risk associated with these receivables. d) Liquidity Risk Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they fall due. The Group’s approach to managing liquidity is to ensure that it will have sufficient liquidity to meet its liabilities as they become due, without incurring unacceptable losses or risking damage to the Group’s reputation. The Group manages liquidity risk by maintaining adequate reserves and banking facilities by continuously monitoring forecast and actual cash flows, and by matching the maturity profiles of financial assets and liabilities. Financial liabilities are at contractual value, except for provisions, which are estimated at each period end. The Company has the following commitments related to its financial liabilities (US$’000): Less than More than Year ended 31 December 2017 Total 1 year 1 — 5 years 5 years Trade and other payables 9,051 9,051 — — Accrued expenses 39,051 39,051 — — Production prepayment 18,194 18,194 — — Provisions 3,316 1,158 2,158 — Credit facilities payments, including interest (1) 225,933 13,674 212,259 — Total 295,545 81,128 214,417 — Less than More than Year ended 31 December 2016 Total 1 year 1 — 5 years 5 years Trade and other payables 3,579 3,579 — — Accrued expenses 19,995 19,995 — — Provisions 6,025 2,726 3,299 — Credit facilities payments, including interest (1) 235,441 12,606 222,835 — Total 265,040 38,906 226,134 — (1) Assumes credit facilities are held to maturity. e) Market Risk Market risk is the risk that the fair value of future cash flows of a financial instrument will fluctuate because of changes in market prices. Market risk comprises three types of risk: commodity price risk, interest rate risk and foreign currency risk. Financial instruments affected by market risk include loans and borrowings, deposits, trade receivables, trade payables, accrued liabilities and derivative financial instruments. Commodity Price Risk The Group is exposed to the risk of fluctuations in prevailing market commodity prices on the mix of oil, gas and NGL products it produces. Commodity Price Risk Sensitivity Analysis The table below summarises the impact on profit before tax for changes in commodity prices on the fair value of derivative financial instruments. The impact on equity is the same as the impact on profit before tax as these derivative financial instruments have not been designated as hedges and are and therefore adjusted to fair value through profit and loss. The analysis assumes that the crude oil and natural gas price moves $10 per barrel and $0.50 per mcf, with all other variables remaining constant, respectively. 2017 2016 Year ended 31 December US$’000 US$’000 Effect on profit before tax Increase / (Decrease) Oil - improvement in US$ oil price of $10 per barrel (14,287) (12,813) - decline in US$ oil price of $10 per barrel 15,961 16,233 Gas - improvement in US$ gas price of $0.50 per mcf (1,254) (1,423) - decline in US$ gas price of $0.50 per mcf 1,504 1,306 Interest Rate Risk Interest rate risk is the risk that the fair value of the future cash flows of a financial instrument will fluctuate because of changes in market interest rates. The Group’s exposure to the risk of changes in market interest rates relates primarily to the Group’s long-term debt obligations with floating interest rates. Interest Rate Sensitivity Analysis Based on the net debt position as at 31 December 2017 and 2016 with all other variables remaining constant, the following table represents the effect on income as a result of changes in the interest rate. The impact on equity is the same as the impact on profit (loss) before income tax. 2017 2016 Year ended 31 December US$’000 US$’000 Effect on profit (loss) before tax Increase / (Decrease) - increase in interest rates + 2% (3,663) (3,357) - decrease in interest rates - 2% 1,177 396 This assumes that the change in interest rates is effective from the beginning of the financial year and the net debt position and fixed/floating mix is constant over the year. However, interest rates and the debt profile of the Group are unlikely to remain constant and therefore the above sensitivity amounts are subject to change. |
SUBSIDIARIES
SUBSIDIARIES | 12 Months Ended |
Dec. 31, 2017 | |
SUBSIDIARIES | |
SUBSIDIARIES | NOTE 36 — SUBSIDIARIES The Company’s significant subsidiaries as at 31 December 2017 are as follows: Name of Entity Place of Incorporation Percentage Owned Sundance Energy Inc. Colorado 100 Sundance Energy Oklahoma, LLC Delaware 100 SEA Eagle Ford, LLC Texas 100 Armadillo Eagle Ford Holdings, Inc.(1) Delaware 100 Armadillo E&P, Inc. Delaware 100 NSE PEL570 LTD Australia 100 (1) Entity was dissolved subsequent to 31 December 2017. |
EVENTS AFTER THE BALANCE SHEET
EVENTS AFTER THE BALANCE SHEET DATE | 12 Months Ended |
Dec. 31, 2017 | |
EVENTS AFTER THE BALANCE SHEET DATE | |
EVENTS AFTER THE BALANCE SHEET DATE | NOTE 37 — EVENTS AFTER THE BALANCE SHEET DATE On 23 April 2018, the Company’s wholly owned subsidiary Sundance Energy, Inc. acquired from Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC (collectively the “Sellers”) approximately 21,900 net acres in the Eagle Ford oil, volatile oil, and condensate windows in McMullen, Live Oak, Atascosa and La Salle counties, Texas for a cash purchase price of $221.5 million. To finance the acquisition, the Company raised $260.0 million of capital through the issuance of 5,614,447,268 ordinary shares. Contemporaneous with the acquisition closing, on 23 April 2018, the Company entered a $250 million syndicated second lien term loan with Morgan Stanley Energy Capital, as administrative agent, and the lenders from time to time party thereto, and a syndicated revolver with Natixis, New York Branch, as administrative agent, and the lenders from time to time party thereto, with initial availability of $87.5 million (with a $250.0 million face). The proceeds of the refinanced debt facilities were used to retire the Company’s existing Credit Facilities of $192.0 million, repay the remaining outstanding production prepayment of $11.8 million and pay deferred financing fees of $15.9 million. |
UNAUDITED SUPPLEMENTAL OIL AND
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | 12 Months Ended |
Dec. 31, 2017 | |
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | NOTE 38—UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES Costs Incurred The following table sets forth the capitalised costs incurred in our oil and gas production, exploration, and development activities: Year ended December 31, (in thousands) 2017 2016 2015 Property acquisition costs Proved $ 4,335 $ 23,873 $ 13,170 Unproved 1,244 2,815 15,495 Exploration costs 2,949 1,650 10,353 Development costs (1) 115,120 61,131 76,831 $ 123,648 $ 89,469 $ 115,849 (1) 2016 and 2015 development costs include $5.0 million and $16.6 million of costs associated with non-producing wells in progress as at December 31, 2016 and 2015, respectively. These wells in progress were either drilling, waiting on hydraulic fracturing or production testing at year-end. There were no wells in progress at December 31, 2017. SEC Oil and Gas Reserve Information Ryder Scott Company, L.P., an independent petroleum engineering consulting firm, prepared all of the total future net revenue discounted at 10% attributable to the total interest owned by the Company as of December 31, 2017, 2016 and 2015. The technical person primarily responsible for the estimates set forth in the reserves report is Mr. Stephen E. Gardner. Mr. Gardner is a Licensed Professional Engineer in the States of Colorado and Texas with over 12 years of practical experience in estimation and evaluation of petroleum reserves. 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 Total Oil Oil Gas NGL Equivalents (MBbl) (MMcf) (MBbl) (MBoe) Total proved reserves: 31 December 2014 17,026 28,733 4,166 25,981 Revisions of previous estimates (3,491) (8,152) (1,218) (6,068) Extensions and discoveries 1,950 4,122 699 3,336 Purchases of reserves in-place 3,896 4,454 238 4,876 Production (1,829) (2,581) (393) (2,652) Sales of reserves in-place — — — — 31 December 2015 17,552 26,576 3,492 25,473 Revisions of previous estimates (1,397) 536 (833) (2,141) Extensions and discoveries 4,242 10,240 1,551 7,500 Purchases of reserves in-place 1,432 3,121 1,216 3,168 Production (1,412) (2,941) (332) (2,234) Sales of reserves in-place (1,976) (1,802) — (2,276) 31 December 2016 18,441 35,730 5,094 29,490 Revisions of previous estimates (1,778) (2,091) 154 (1,972) Extensions and discoveries 6,658 17,255 2,852 12,386 Purchases of reserves in-place 6,892 14,935 1,897 11,278 Production (1,800) (3,621) (324) (2,727) Sales of reserves in-place (426) (2,799) (483) (1,376) 31 December 2017 27,987 59,409 9,190 47,079 Proved developed reserves: 31 December 2015 6,379 13,205 1,998 10,578 31 December 2016 7,440 16,704 2,269 12,493 31 December 2017 8,987 21,078 3,244 15,744 Proved undeveloped reserves 31 December 2015 11,173 13,371 1,494 14,895 31 December 2016 11,001 19,026 2,825 16,997 31 December 2017 19,000 38,331 5,946 31,335 Proved Undeveloped Reserves At December 31, 2017, the Company’s proved undeveloped reserves were approximately 31,335 MBoe, an increase of 14,338 MBoe over our December 31, 2016 proved undeveloped reserves estimate of approximately 16,997 MBoe. The change primarily consisted of extensions and discoveries of 10,140 MBoe (Eagle Ford) and purchases of reserves of 10,678 MBoe (from its leasehold acquisitions in the second quarter of 2017), partially offset by downward revisions to previous estimates of approximately 2,534 MBoe and a decrease of 3,948 MBoe due to the conversion of proved undeveloped reserves to proved developed reserves. All of the proved undeveloped reserves at December 31, 2017 were located in the Eagle Ford. Over the next five years, the Company expects to fund its future development costs associated with proved undeveloped reserves of $508.5 million with operating cash flows from its existing proved developed reserves and proved undeveloped reserves that are expected to be converted to proved developed reserves, supplemented by its revolving credit facility . Using the December 31, 2017 SEC price assumptions, the Company’s proved reserves operating cash flows are expected to be approximately $806.1 million (undiscounted, before income taxes (if any)). As such, the Company expects all proved undeveloped locations that are scheduled and included in the Company’s reserves will be spud within the next five years. Revisions of Previous Estimates The Company’s previous estimates of Proved Reserves related to the Eagle Ford decreased by 1,972 MBoe in 2017. This decrease was primarily due to the derecognition of certain proved undeveloped reserves as they were not drilled within the initial five year window. The Company’s previous estimates of Proved Reserves related to the Eagle Ford decreased by 2,141 MBoe in 2016 (100% percent of the Company’s total revisions of previous estimate). This decrease was due to the majority of the Company’s previous Eagle Ford Proved Undeveloped Reserves becoming uneconomic as the result of adjusted forecasts and lower oil, natural gas and NGL pricing. The Company’s previous estimates of Proved Reserves related to the Mississippian/Woodford formation decreased by 5,900 MBoe in 2015 (97 percent of the Company’s total revisions of previous estimate). This decrease was due to the majority of the Company’s previous Mississippian/Woodford Proved Undeveloped Reserves becoming uneconomic as the result of lower oil, natural gas and NGL pricing. Extensions and Discoveries The Company had extensions and discoveries 12,386 MBoe during 2017, primarily resulting from the 2017 drilling program in Dimmit and McMullen Counties, targeting the Eagle Ford formation. As a result of the Company’s 2016 drilling programs in Dimmit and McMullen Counties, targeting the Eagle Ford formation, the Proved Reserves had extensions and discoveries of 7,500 MBoe, which represent 100% of the Company’s total extensions and discoveries. As a result of the Company’s 2015 drilling programs in Dimmit County targeting the Eagle Ford formation, the Proved Reserves had extensions and discoveries of 3,303 MBoe, which represent 99% of the Company’s total extensions and discoveries. Purchase of Reserves In-Place During the years ended 31 December 2017, 2016 and 2015, our purchases of reserves were located in the Eagle Ford. Sales of Reserves In-Place During the year ended 31 December 2017, the Company’s sales of reserves were attributed to the Mississippian/Woodward formations. The Company divested of its Oklahoma assets in May 2017. See Note 3. During the year ended 31 December 2016, the Company’s sales of reserves were located in the Atascosa County, Texas, of the Eagle Ford formation. During the year ended 31 December 2015, we did not have any sales of reserves in-place. 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. 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: Year ended 31 December (in thousands) 2017 2016 2015 Cash inflows $ 1,866,923 $ 892,576 $ 936,041 Production costs (667,438) (307,907) (246,277) Development costs (516,243) (274,384) (308,253) Income tax expense (35,933) — (1,602) Net cash flow 647,309 310,285 379,909 10% annual discount rate (280,562) (151,146) (198,142) Standardized measure of discounted future net cash flow $ 366,747 $ 159,139 $ 181,767 The following are the principal sources of change in the Standardized Measure: Year ended 31 December (in thousands) 2017 2016 2015 Standardized Measure, beginning of period $ 159,139 $ 181,767 $ 435,506 Sales, net of production costs (75,370) (49,496) (67,693) Net change in sales prices, net of production costs 7,899 (62,670) (369,770) Extensions and discoveries, net of future production and development costs 94,151 3,603 11,609 Changes in future development costs 17,128 5,331 28,092 Previously estimated development costs incurred during the period 51,414 45,012 31,007 Revision of quantity estimates (20,598) 9,762 (91,440) Accretion of discount 15,914 18,217 53,173 Change in income taxes (14,492) 402 95,827 Purchases of reserves in-place 88,280 17,004 442 Sales of reserves in-place (7,544) 845 — Change in production rates and other 50,826 (10,638) 55,014 Standardized Measure, end of period $ 366,747 $ 159,139 $ 181,767 (1) The 2017 change in production rates and other is primarily related to the Company accelerating the recoveries of reserves. 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. If future gas sales are covered by contracts at specified prices, the contract prices would be used. Fluctuations in prices are due to supply and demand and are beyond our control. The following average prices were used in determining the Standardized Measure as at: Year ended 31 December 2017 2016 2015 Oil price per Bbl $ 52.60 $ 42.02 $ 48.47 Gas price per Mcf $ 3.17 $ 1.22 $ 1.27 NGL price per Bbl $ 22.47 $ 14.55 $ 14.80 The Company calculates the projected income tax effect using the “year- by-year” method for purposes of the supplemental oil and gas disclosures. |
STATEMENT OF SIGNIFICANT ACCO44
STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES (Policies) | 12 Months Ended |
Dec. 31, 2017 | |
STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES | |
Basis of Preparation | Basis of Preparation The consolidated financial report is a general purpose financial report that has been prepared in accordance with Australian Accounting Standards, Australian Accounting Interpretations, other authoritative pronouncements of the Australian Accounting Standards Board (“AASB”) and the Corporations Act 2001. These consolidated financial statements comply with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”). Material accounting policies adopted in the preparation of this financial report are presented below. They have been consistently applied unless otherwise stated. The consolidated financial statements are prepared on a historical basis, except for the revaluation of certain non-current assets and financial instruments, as explained in the accounting policies below. The consolidated financial statements are presented in US dollars and all values are rounded to the nearest thousand (US$’000), except where stated otherwise. |
Principles of Consolidation | Principles of Consolidation The consolidated financial statements incorporate the assets and liabilities as at December 31 2017 and 2016, and the results for the years then ended, of Sundance Energy Australia Limited (“SEAL”) and the entities it controls. A controlled entity is any entity over which SEAL is exposed, or has rights to variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. As at 31 December 2017 and 2016, all of its controlled entities were wholly-owned. All inter-group balances and transactions between entities in the Group, including any recognised profits or losses, are eliminated on consolidation. |
Income Tax | a) Income Tax The income tax expense for the period comprises current income tax expense and deferred income tax expense. Current income tax expense charged to the statement of profit or loss is the tax payable on taxable income calculated using applicable income tax rates enacted, or substantially enacted, as at the reporting date. Current tax liabilities/(assets) are therefore measured at the amounts expected to be paid to/(recovered from) the relevant taxation authority. Deferred income tax expense reflects movements in deferred tax asset and deferred tax liability balances during the period. Current and deferred income tax expense/(income) is charged or credited directly to equity instead of the statement of profit or loss when the tax relates to items that are credited or charged directly to equity. Deferred tax assets and liabilities are ascertained based on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the financial statements. Deferred tax assets also result where amounts have been fully expensed but future tax deductions are available. No deferred income tax will be recognised from the initial recognition of an asset or liability, excluding a business combination, where there is no effect on accounting or taxable profit or loss. Deferred tax assets and liabilities are calculated at the tax rates that are expected to apply to the period when the asset recognised or the liability is settled, based on tax rates enacted or substantively enacted at the reporting date. Their measurement also reflects the manner in which management expects to recover or settle the carrying amount of the related asset or liability. Deferred tax assets relating to temporary differences and unused tax losses are recognised only to the extent that it is probable that future taxable profit will be available against which the benefits of the deferred tax asset can be utilized. Where temporary differences exist in relation to investments in subsidiaries, branches, associates, and joint ventures, deferred tax assets and liabilities are not recognised where the timing of the reversal of the temporary difference can be controlled and it is not probable that the reversal will occur in the foreseeable future. Current tax assets and liabilities are offset where a legally enforceable right of set-off exists and it is intended that net settlement or simultaneous realisation and settlement of the respective asset and liability will occur. Deferred tax assets and liabilities are offset where a legally enforceable right of set-off exists, the deferred tax assets and liabilities relate to income taxes levied by the same taxation authority on either the same taxable entity or different taxable entities where it is intended that net settlement or simultaneous realisation and settlement of the respective asset and liability will occur in future periods in which significant amounts of deferred tax assets or liabilities are expected to be recovered or settled. Tax Consolidation Sundance Energy Australia Limited and its wholly-owned Australian controlled entities have implemented the income tax consolidation regime, with Sundance Energy Australia Limited being the head company of the consolidated group. Under this regime the group entities are taxed as a single taxpayer. In addition to its own current and deferred tax amounts, Sundance Energy Australia Limited, as head company, also recognises the current tax liabilities (or assets) and the deferred tax assets arising from unused tax losses and unused tax credits assumed from controlled entities in the tax consolidated group. |
Exploration and Evaluation Expenditure | b) Exploration and Evaluation Expenditure Exploration and evaluation expenditures incurred are accumulated in respect of each identifiable area of interest. These costs are capitalised to the extent that they are expected to be recouped through the successful development of the area or where activities in the area have not yet reached a stage that permits reasonable assessment of the existence of economically recoverable reserves. Any such estimates and assumptions may change as new information becomes available. If, after the expenditure is capitalised, information becomes available suggesting that the recovery of the expenditure is unlikely, for example a dry hole, the relevant capitalised amount is written off in the consolidated statement of profit or loss and other comprehensive income in the period in which new information becomes available. The costs of assets constructed within the Group includes the leasehold cost, geological and geophysical costs, and an appropriate proportion of fixed and variable overheads directly attributable to the exploration and acquisition of undeveloped oil and gas properties. When approval of commercial development of a discovered oil or gas field occurs, the accumulated costs for the relevant area of interest are transferred to development and production assets. The costs of developed and producing assets are amortised over the life of the area according to the rate of depletion of the proved and probable developed reserves. The costs associated with the undeveloped acreage are not subject to depletion. The carrying amounts of the Group’s exploration and evaluation assets are reviewed at each reporting date to determine whether any impairment indicators exist. Impairment indicators could include i) tenure over the licence area has expired during the period or will expire in the near future, and is not expected to be renewed, ii) substantive expenditure on further exploration for and evaluation of mineral resources in the specific area is not budgeted or planned, iii) exploration for and evaluation of resources in the specific area have not led to the discovery of commercially viable quantities of resources, and the Group has decided to discontinue activities in the specific area, or iv) sufficient data exist to indicate that although a development is likely to proceed, the carrying amount of the exploration and evaluation asset is unlikely to be recovered in full from successful development or from sale. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made and any resulting impairment loss is recognized in the consolidated statement of profit or loss and other comprehensive income. The estimate of the recoverable amount is made consistent with the methods described under Impairment in (d) below. |
Development and Production Assets and Property and Equipment | c) Development and Production Assets and Property and Equipment Development and production assets, and property and equipment are carried at cost less, where applicable, any accumulated depreciation, amortisation and impairment losses. The costs of assets constructed within the Group includes the cost of materials, direct labor, borrowing costs and an appropriate proportion of fixed and variable overheads directly attributable to the acquisition or development of oil and gas properties and facilities necessary for the extraction of resources. Repairs and maintenance are charged to the consolidated statement of profit or loss and comprehensive income during the financial period in which are they are incurred. |
Depreciation and Amortisation Expense | Depreciation and Amortisation Expense Property and equipment are depreciated on a straight-line basis over their useful lives from the time the asset is held and ready for use. Leasehold improvements are depreciated over the shorter of either the unexpired period of the lease or the estimated useful life of the improvement. The depreciation rates used for each class of depreciable assets are: Class of Non-Current Asset Depreciation Rate Basis of Depreciation Property and Equipment 5 – 33 % Straight Line The Group uses the units-of-production method to amortise costs carried forward in relation to its development and production assets. For this approach, the calculation is based upon economically recoverable reserves over the life of an asset or group of assets. The assets’ residual values and useful lives are reviewed, and adjusted if appropriate, at the end of each reporting period. |
Impairment | d) Impairment The carrying amount of development and production assets and property and equipment are reviewed at each reporting date to determine whether there is any indication of impairment. Where an indicator of impairment exists, a formal estimate of the recoverable amount is made. Development and production assets are assessed for impairment on a cash-generating unit basis. A cash-generating unit (“CGU”) is the smallest grouping of assets that generates independent cash inflows. Management has assessed its CGUs as being an individual basin, which is the lowest level for which cash inflows are largely independent of those of other assets. Each of the Group’s development and production asset CGUs include all of its developed producing properties, shared infrastructure supporting its production and undeveloped acreage that the Group considers technically feasible and commercially viable. An impairment loss is recognized in the consolidated statement of profit and loss whenever the carrying amount of an asset or its cash-generating unit exceeds its recoverable amount. Impairment losses recognised in respect of cash-generating units are allocated to reduce the carrying amount of the assets in the unit on a pro-rata basis. The recoverable amount of an asset is the greater of its fair value less costs to sell (“FVLCS”) or its value-in-use (“VIU”). In assessing VIU, an asset’s estimated future cash flows are discounted to their present value using an appropriate discount rate that reflects current market assessments of the time value of money and the risks specific to the assets/CGUs. The estimated future cash flows for the VIU calculation are based on estimates, the most significant of which are hydrocarbon reserves, future production profiles, commodity prices, operating costs and any future development costs necessary to produce the reserves. Estimates of future commodity prices are based on the Group’s best estimates of future market prices with reference to bank price surveys, external market analysts’ forecasts, and forward curves. The discount rates applied to the future forecast cash flows are based on a third party participant’s post-tax weighted average cost of capital, adjusted for the risk profile of the asset. Under a FVLCS calculation, the Group considers market data related to recent transactions for similar assets. In determining the fair value of the Group’s investment in shale properties, the Group considers a variety of valuation metrics from recent comparable transactions in the market. These metrics include price per flowing barrel of oil equivalent and undeveloped land values per net acre held. Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the group and the cost of the item can be measured reliably. An impairment loss is reversed if there has been an increase in the estimated recoverable amount of a previously impaired assets. An impairment loss is reversed only to the extent that the asset’s carrying amount does not exceed the carrying amount that would have been determined, net of depreciation or depletion if no impairment loss had been recognized. The Company has not reversed an impairment loss during the years ended 31 December 2017, 2016 and 2015. If an entire CGU is disposed, gains and losses on disposals are determined by comparing proceeds with the carrying amount. These gains and losses are included in the statement of profit or loss. If a disposition is less than an entire CGU and the property had been previously subjected to amortization or impairment at the CGU level, and there would be no significant impact to the Company’s depletion rate, no gain or loss is recognized and the proceeds of the sale are treated as a cost reduction to the Company’s net book value of the CGU in which the assets were previously included. |
Leases | e) Leases The determination of whether an arrangement is, or contains, a lease is based on the substance of the arrangement at date of inception. The arrangement is assessed to determine whether its fulfillment is dependent on the use of a specific asset or assets and whether the arrangement conveys a right to use the asset, even if that right is not explicitly specified in an arrangement. Leases are classified as finance leases when the terms of the lease transfer substantially all the risks and benefits incidental to the ownership of the asset, but not the legal ownership to the entities in the Group. All other leases are classified as operating leases. Finance leases are capitalised by recording an asset and a liability at the lower of the amounts equal to the fair value of the leased property or the present value of the minimum lease payments, including any guaranteed residual values. Lease payments are allocated between the reduction of the lease liability and the lease interest expense for the period. Assets under financing leases are depreciated on a straight-line basis over the shorter of their estimated useful lives or the lease term. Lease payments for operating leases, where substantially all the risks and benefits remain with the lessor, are charged as expenses in the periods in which they are incurred. Lease incentives under operating leases are recognised as a liability and amortised on a straight-line basis over the life of the lease term. |
Financial Instruments | f) Financial Instruments Recognition and Initial Measurement Financial instruments, incorporating financial assets and financial liabilities, are recognised when the entity becomes a party to the contractual provisions of the instrument. Trade date accounting is adopted for financial assets that are delivered within timeframes established by marketplace convention. Financial instruments are initially measured at fair value plus transactions costs where the instrument is not classified at fair value through profit or loss. Transaction costs related to instruments classified at fair value through profit or loss are expensed to profit or loss immediately. Financial instruments are classified and measured as set out below. Derivative Financial Instruments The Group uses derivative financial instruments to economically hedge its exposure to changes in commodity prices arising in the normal course of business. The principal derivatives that may be used are commodity crude oil or natural gas price swap, option and costless collar contracts. Their use is subject to policies and procedures as approved by the Board of Directors. The Group does not trade in derivative financial instruments for speculative purposes. Derivative financial instruments, which do not qualify as “own-use”, are initially recognised at fair value and remeasured at each reporting period. The fair value of these derivative financial instruments is the estimated amount that the Group would receive or pay to terminate the contracts at the reporting date, taking into account current market prices and the current creditworthiness of the contract counterparties. The derivatives are valued on a mark to market valuation and the gain or loss on re-measurement to fair value is recognised through the statement of profit or loss and other comprehensive income. The Company has designated one oil marketing contract that meets the definition of a derivative as own-use, which under IFRS is not accounted for as a derivative. As a result, the revenues associated with such contract are recognized during the period when volumes are physically delivered. i) Financial assets are classified at fair value through profit or loss when they are acquired principally for the purpose of selling in the near-term. Realised and unrealised gains and losses arising from changes in fair value are included in profit or loss in the period in which they arise. ii) Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market and are subsequently measured at amortised cost using the effective interest rate method. Derecognition Financial assets are derecognised when the contractual right to receipt of cash flows expires or the asset is transferred to another party whereby the entity no longer has any significant continuing involvement in the risks and benefits associated with the asset. Financial liabilities are derecognised when the related obligations are either discharged, cancelled or expire. The difference between the carrying value of the financial liability extinguished or transferred to another party and the fair value of consideration paid, including the transfer of non-cash assets or liabilities assumed, is recognised in profit or loss. |
Foreign Currency Transactions and Balances | g) Foreign Currency Transactions and Balances Functional and Presentation Currency Both the functional currency and the presentation currency of the Group is US dollars. Some subsidiaries have Australian dollar functional currencies which are translated to the presentation currency. All operations of the Group are incurred at subsidiaries where the functional currency is the US dollar as its core oil and gas properties are located in the United States. Transactions and Balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the date of the transaction. Foreign currency monetary items are translated at the year-end exchange rate. Non-monetary items measured at historical cost continue to be carried at the exchange rate at the date of the transaction. Non-monetary items measured at fair value are reported at the exchange rate at the date when fair values were determined. Exchange differences arising on the translation of non-monetary items are recognised directly in equity to the extent that the gain or loss is directly recognised in equity, otherwise the exchange difference is recognised in the consolidated statement of profit or loss and other comprehensive income. Group Companies The financial results and position of foreign subsidiaries whose functional currency is different from the Group’s presentation currency are translated as follows: assets and liabilities are translated at year-end exchange rates prevailing at that reporting date; revenues and expenses are translated to USD using the exchange rate at the date of transaction; and retained profits and issued capital are translated at the exchange rates prevailing at the date of the transaction. Exchange differences arising on translation of foreign operations are transferred directly to the Group’s foreign currency translation reserve. These differences are recognised in the statement of profit or loss and other comprehensive income upon disposal of the foreign operation. |
Employee benefits | h) Employee Benefits Employee benefits that are expected to be settled within one year have been measured at the amounts expected to be paid when the liability is settled. |
Equity-Settled and Deferred Cash Compensation | Equity - Settled Compensation The Group has an incentive compensation plan where employees may be issued shares and/or options. 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 group has a restricted share unit (“RSU”) plan to motivate management and employees to make decisions benefiting long-term value creation, retain management and employees and reward the achievement of the Group’s long-term goals. The target RSUs are generally based on goals established by the Remuneration and Nominations Committee and approved by the Board. The fair value of time-based RSUs is determined based on the price of the Company’s ordinary shares on the date of grant and the expense is recognized over the vesting period. Certain of its RSUs vest based on the achievement of metrics related to the Company’s 3‑year absolute shareholder return or total shareholder return as compared to its peer group, as defined. The Company uses 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 is 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 Australian Treasury bond relevant to the term of the RSU award. Deferred Cash Compensation In 2016 and 2017, the Group granted deferred cash compensation awards to certain employees, which may be earned through appreciation in the volume weighted average price of the Company’s ordinary shares over periods of one to three years. The awards may ultimately be settled in cash or fully vested RSUs at the discretion of the Board. The Group recognizes general and administrative expense for the deferred cash compensation to the extent to which the employees have rendered services, with a corresponding liability included within other noncurrent liabilities on the consolidated statement of financial position. The fair value of the deferred cash awards are estimated initially and at the end of each reporting period until settled, using a Monte Carlo model that takes into consideration the terms and conditions of the award. 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 U.S. Treasury bond relevant to the term of the award. |
Provisions | i) Provisions Provisions are recognised when the group has a legal or constructive obligation, as a result of past events, for which it is probable that an outflow of economic benefits will result and that outflow can be reliably measured. As of 31 December 2017, the Company had recognized a provisions related to a third-party refracturing agreement ($3.3 million). |
Cash and Cash Equivalents | j) Cash and Cash Equivalents Cash and cash equivalents include cash on hand, deposits held at call with banks, and other short-term highly liquid investments with original maturities of three months or less. |
Revenue | k) Revenue Revenue from the sale of oil and natural gas is recognised upon the delivery of product to the purchaser and title transfers to the purchaser. The Company uses the sales method of accounting for natural gas imbalances in those circumstances where it has under-produced or over-produced its ownership percentage in a property. Under this method, a receivable or payable is recognized only to the extent an imbalance cannot be recouped from the reserves in the underlying properties. The Company had not recognized an imbalance on the consolidated statement of financial position as at 31 December 2017 and 2016. All revenue is stated net of royalties and transportation costs. |
Borrowing Costs | l) Borrowing Costs Borrowing costs, including interest, directly attributable to the acquisition, construction or production of assets that necessarily take a substantial period of time to prepare for their intended use or sale are added to the cost of those assets until such time as the assets are substantially ready for their intended use or sale. Borrowings are recognised initially at fair value, net of transaction costs incurred. Subsequent to initial recognition, borrowings are stated as amortised cost with any difference between cost and redemption being recognised in the consolidated statement of profit or loss and other comprehensive income over the period of the borrowings on an effective interest basis. The Company capitalised eligible borrowing costs of $1.4 million and $1.1 million for the years ended 31 December 2017 and 2016, respectively. All other borrowing costs are recognised in the consolidated statement of profit or loss and other comprehensive income in the period in which they are incurred. |
Goods and Services Tax | m) Goods and Services Tax Expenses and assets are recognised net of the amount of Goods and Service Tax (“GST”), except where the amount of GST incurred is not recoverable from the Australian Tax Office. In these circumstances the GST is recognised as part of the cost of acquisition of the asset or as part of an item of the expense. Receivables and payables in the statement of financial position are shown inclusive of GST. Cash flows are presented in the consolidated statement of cash flows on a gross basis except for the GST component of investing and financing activities, which are disclosed as operating cash flows. |
Business Combinations | n) Business Combinations A business combination is a transaction in which an acquirer obtains control of one or more businesses. The acquisition method of accounting is used to account for all business combinations regardless of whether equity instruments or other assets are acquired. The acquisition method is only applied to a business combination when control over the business is obtained. Subsequent changes in interests in a business where control already exists are accounted for as transactions between owners. The cost of the business combination is measured at fair value of the assets given, shares issued and liabilities incurred or assumed at the date of acquisition. Costs directly attributable to the business combination are expensed as incurred, except those directly and incrementally attributable to equity issuance. The excess of the consideration transferred, the amount of any non-controlling interest in the acquiree and the acquisition-date fair value of any previous equity interest in the acquiree over the fair value of the net identifiable asset acquired, if any, is recorded as goodwill. If those amounts are less than the fair value of the net identifiable assets of the subsidiary acquired and the measurement of all amounts has been reviewed, the difference is recognised directly in the consolidated statement of profit or loss and other comprehensive income as a gain on bargain purchase. Adjustments to the purchase price and excess on consideration transferred may be made up to one year from the acquisition date. |
Assets Held for Sale | o) Assets Held for Sale The Company classifies property as held for sale when management commits to a plan to sell the property, the plan has appropriate approvals, the sale of the property is highly probable within the next twelve months, and certain other criteria are met. At such time, the respective assets and liabilities are presented separately on the Company’s consolidated statement of financial position and amortisation is no longer recognized. Assets held for sale are reported at the lower of their carrying amount or their estimated fair value, less the costs to sell the assets. The Company recognizes an impairment loss if the current net book value of the property exceeds its fair value, less selling costs. As at 31 December 2017, based upon the Company’s intent and anticipated ability to sell an interest in these properties, the Company had classified its Dimmit County, Texas properties as held for sale. As at 31 December 2016 the Company had its Mississippian/Woodward properties classified as held for sale. |
Critical Accounting Estimates and Judgements | p) Critical Accounting Estimates and Judgements The Directors evaluate estimates and judgements incorporated into the financial report based on historical knowledge and best available current information. Estimates assume a reasonable expectation of future events and are based on current trends and economic data obtained both externally and within the Group. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods. Management has made the following judgements, which have the most significant effect on the amounts recognised in the consolidated financial statements. Estimates of reserve quantities The estimated quantities of hydrocarbon reserves reported by the Group are integral to the calculation of amortisation (depletion) and to assessments of possible impairment of assets. Estimated reserve quantities are based upon interpretations of geological and geophysical models and assessment of the technical feasibility and commercial viability of producing the reserves. The Company engaged an independent petroleum engineering firm, Ryder Scott Company to prepare its reserve estimates which conform to SEC guidelines. These assessments require assumptions to be made regarding future development and production costs, commodity prices, exchange rates and fiscal regimes. The estimates of reserves may change from period to period as the economic assumptions used to estimate the reserves can change from period to period, and as additional geological and production data are generated during the course of operations. Impairment of Non-Financial Assets The Group assesses impairment at each reporting date by evaluating conditions specific to the Group that may lead to impairment of assets. Where an indicator of impairment exists, the recoverable amount of the cash-generating unit to which the assets belong is then estimated based on the present value of future discounted cash flows. For development and production assets, the expected future cash flow estimation is based on a number of factors, variables and assumptions, the most important of which are estimates of reserves, future production profiles, commodity prices and costs. In most cases, the present value of future cash flows is most sensitive to estimates of future oil price and discount rates. A change in the modeled assumptions in isolation could materially change the recoverable amount. However, due to the interrelated nature of the assumptions, movements in any one variable can have an indirect impact on others and individual variables rarely change in isolation. Additionally, management can be expected to respond to some movements, to mitigate downsides and take advantage of upsides, as circumstances allow. Consequently, it is impracticable to estimate the indirect impact that a change in one assumption has on other variables and therefore, on the extent of impairments under different sets of assumptions in subsequent reporting periods. In the event that future circumstances vary from these assumptions, the recoverable amount of the Group’s development and production assets could change materially and result in impairment losses or the reversal of previous impairment losses. Exploration and Evaluation The Company’s policy for exploration and evaluation is discussed in Note 1 (b). The application of this policy requires the Company to make certain estimates and assumptions as to future events and circumstances, particularly in relation to the assessment of whether economic quantities of reserves have been found. Any such estimates and assumptions may change as new information becomes available. If, after having capitalised exploration and evaluation expenditure, management concludes that the capitalised expenditure is unlikely to be recovered by future sale or exploitation, then the relevant capitalised amount will be written off through the consolidated statement of profit or loss and other comprehensive income. Restoration Provision A provision for rehabilitation and restoration is provided by the Group to meet all future obligations for the restoration and rehabilitation of oil and gas producing areas when oil and gas reserves are exhausted and the oil and gas fields are abandoned. Restoration liabilities are discounted to present value and capitalised as a component part of capitalised development expenditure. The capitalised costs are amortised over the units of production and the provision is revised at each balance sheet date through the consolidated statement of profit or loss and other comprehensive income as the discounting of the liability unwinds. In most instances, the removal of the assets associated with these oil and gas producing areas will occur many years in the future. The estimate of future removal costs therefore requires management to make significant judgements regarding removal date or well lives, the extent of restoration activities required, discount and inflation rates. Units of Production Depletion Development and production assets are depleted using the units of production method over economically recoverable reserves. This results in a depletion or amortisation charge proportional to the depletion of the anticipated remaining production from the area of interest. The life of each item has regard to both its physical life limitations and present assessments of economically recoverable reserves of the field at which the asset is located. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the units of production rate of depletion or amortisation could be impacted to the extent that actual production in the future is different from current forecast production based on total economically recoverable reserves, or future capital expenditure estimates change. Changes to economically recoverable reserves could arise due to change in the factors or assumptions used in estimating reserves, including the effect on economically recoverable reserves of differences between actual commodity prices and commodity price assumptions and unforeseen operational issues. Changes in estimates are accounted for prospectively. Share-based Compensation The Group’s policy for share-based compensation is discussed in Note 1 (h). The application of this policy requires management to make certain estimates and assumptions as to future events and circumstances. Certain of the Company’s restricted share units vest based on the Company’s ordinary share price appreciation over a 3- year period in absolute terms or as compared to a defined peer group. Share-based compensation related to these awards use estimates for the expected volatility of the Company’s ordinary share price and of its peer’s ordinary share price (total shareholder return shares). The Company’s deferred cash awards also vest upon the Company’s ordinary share price appreciation through 2017, 2018 and 2019. The Company must also estimate expected volatility of the Company’s ordinary share price when valuing these awards. |
Rounding of Amounts | q) Rounding of Amounts In accordance with the Australian Securities and Investment Commission (“ASIC”) Corporations (Rounding in Financial/Directors’ Reports) Instrument 2016/191, amounts in the financial statements have been rounded to the nearest thousand, unless otherwise indicated. |
Earnings (Loss) Per Share | r) Earnings (Loss) Per Share The group presents basic and diluted earnings (loss) per share for its ordinary shares. Basic earnings (loss) per share is calculated by dividing the profit or loss attributable to ordinary shareholders of the Company by the weighted average number of ordinary shares outstanding during the year. Diluted earnings (loss) per share is determined by adjusting the profit or loss attributable to ordinary shareholders and the weighted average number of ordinary shares for the dilutive effect, if any, of outstanding share rights and share options which have been issued to employees. |
New and Revised Accounting Standards | s) New and Revised Accounting Standards The Group has adopted all of the new and revised Standards and Interpretations issued by IFRS/AASB that are relevant to its operations and effective for the current annual reporting period. The adoption of these new and revised Australian Accounting Standards and Interpretations has had no significant impact on the Group’s accounting policies or the amounts reported during the financial year. The following Standards and Interpretations have been issued but are not yet effective. These are the standards that the Group reasonably expects will have an impact on its disclosures, financial position or performance when applied at a future date. The Group’s assessment of the impact of these new standards, amendments to standards, and interpretations is set out below. AASB 9/IFRS 9 — Financial Instruments, and the relevant amending standards AASB 9/IFRS 9, approved in December 2015, introduces new requirements for the classification, measurement, and derecognition of financial instruments, including new general hedge accounting requirements. The effective date of this standard is for fiscal years beginning on or after 1 January 2018, with early adoption permitted. The Company adopted the standard on 1 January 2018 and it is not expected to have a material impact on the Group’s consolidated financial statements. AASB 15/IFRS 15 — Revenue from Contracts with Customers In May 2014, AASB 15/IFRS 15 was issued which establishes a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. Specifically, the standard introduces a 5‑step approach to revenue recognition: 1. 2. 3. 4. 5. Under AASB 15/IFRS 15, an entity recognizes revenue when (or as) a performance obligation is satisfied, i.e. when ‘control’ of the goods or services underlying the particular performance obligation is transferred to the customer. The standard is required to be adopted using either the full retrospective approach, with all the prior periods presented adjusted, or the modified retrospective approach, with a cumulative adjustment to retained earnings on the opening balance sheet . The new revenue recognition standard is effective for the Company on 1 January 2018, and was adopted on that date using the modified retrospective method. The Company has completed the assessment of its contracts with customers and is in the process of implementing the changes to its financial statements, accounting policies and internal controls as a result of the adoption of this standard. Based upon the analysis performed to date on its contracts with customers, the Company does not expect the adoption of IFRS 15 to have a material effect on net income, cash flows, or the timing of revenue recognition. In addition, the Company is continuing to assess the additional disclosures that will be required upon implementation of the standard. AASB 16/IFRS 16 — Leases In January 2016, AASB 16/IFRS 16 was issued which provides a comprehensive model for the identification of lease arrangements and their treatment in the financial statements for both lessees and lessors. AASB 16/IFRS 16 changes the current accounting for leases to eliminate the operating/finance lease designation and require entities to recognize most leases on the statement of financial position, initially recorded at the fair value of unavoidable lease payments. The entity will then recognize depreciation of the lease assets and interest on the statement of profit or loss. The effective date of this standard is for fiscal years beginning on or after 1 January 2019. As of 31 December 2017, the Company had approximately $2.4 million of contractual obligations related to its non-cancelable leases, and it will evaluate those contracts as well as other existing arrangements to determine if they qualify for lease accounting under AASB 16/IFRS 16. The Company plans to adopt the standard effective 1 January 2019. |
STATEMENT OF SIGNIFICANT ACCO45
STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES | |
Schedule of depreciation rates used for each class of depreciable assets | Class of Non-Current Asset Depreciation Rate Basis of Depreciation Property and Equipment 5 – 33 % Straight Line |
BUSINESS COMBINATIONS (Tables)
BUSINESS COMBINATIONS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Eagle Ford acquisition one | |
BUSINESS COMBINATIONS | |
Schedule of fair value of assets and liabilities as at the date of acquisition | The following table reflects the fair value of the assets acquired and the liabilities assumed as at the date of acquisition (in thousands): Fair value of assets acquired: Development and production assets $ 16,628 Fair value of liabilities assumed: Restoration provision (747) Net assets acquired $ 15,881 Purchase price: Cash consideration $ 15,881 Total consideration paid $ 15,881 |
Eagle Ford acquisition two | |
BUSINESS COMBINATIONS | |
Schedule of fair value of assets and liabilities as at the date of acquisition | The following table reflects the fair value of the assets acquired and the liabilities as at the date of acquisition (in thousands): Fair value of assets acquired: Development and production assets 7,348 Fair value of liabilities assumed: Restoration provision (118) Net assets acquired $ 7,230 Purchase price: Cash consideration $ 7,230 Total consideration paid $ 7,230 |
REVENUE (Tables)
REVENUE (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
REVENUE. | |
Schedule of revenue | 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Oil revenue 89,136 57,296 82,949 Natural gas revenue 8,743 4,937 4,720 Natural gas liquid ("NGL") revenue 6,520 4,376 4,522 Total revenue 104,399 66,609 92,191 |
LEASE OPERATING EXPENSES (Table
LEASE OPERATING EXPENSES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
LEASE OPERATING EXPENSES | |
Schedule of lease operating expenses | 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Lease operating expense (17,127) (11,259) (16,667) Workover expense (5,289) (1,678) (1,788) Total lease operating expense (22,416) (12,937) (18,455) |
GENERAL AND ADMINISTRATIVE EX49
GENERAL AND ADMINISTRATIVE EXPENSES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
GENERAL AND ADMINISTRATIVE EXPENSES | |
Schedule of general and administrative expenses | 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Employee benefits expense, including salaries and wages, net of capitalised overhead (4,088) (3,260) (4,849) Share-based payments expense (1) (1,868) (2,748) (4,100) Legal and other professional fees (6,330) (2,085) (3,347) Corporate fees (1,937) (1,762) (1,986) Rent (632) (669) (993) Regulatory expenses (314) (279) (203) Transaction related costs (2,118) (323) (540) Other expenses (1,058) (984) (1,158) Total general and administrative expenses (18,345) (12,110) (17,176) (1) Share based payment expense includes expense associated with restricted share units and deferred cash awards. See Note 33. |
INCOME TAX EXPENSE (Tables)
INCOME TAX EXPENSE (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
INCOME TAX EXPENSE | |
Summary of income tax expense (benefit) | 2017 2016 2015 Year ended 31 December US$’000 US$’00 US$’000 a) The components of income tax expense comprise: Current tax expense (benefit) (4,688) 1,563 (6,191) Deferred tax expense 2,815 142 (100,947) Total income tax expense (benefit) (1,873) 1,705 (107,138) b) The prima facie tax on loss from ordinary activities before income tax is reconciled to the income tax as follows: Loss before income tax (24,308) (43,989) (370,973) Prima facie tax expense at the Group’s statutory income tax rate of 30% (7,293) (13,197) (111,292) Increase (decrease) in tax expense resulting from: - Change in US Federal tax rate 18,821 — - Difference of tax rate in US controlled entities (53) (2,161) (20,447) - Impact of direct accounting from US controlled entities (1) (8) (98) (3,165) - Share-based compensation 781 539 747 - Other allowable items (83) 314 77 - Refundable AMT Credits (4,688) — — - Change in apportioned state tax rates in US controlled entities — — (84) - Change in unrecognized tax assets 9,471 16,308 27,026 - Change in unrecognized tax assets due to Tax Reform (18,821) — — Total income tax expense (benefit) (1,873) 1,705 (107,138) c) Unused tax losses and temporary differences for which no deferred tax asset has been recognised at 30% 36,672 46,022 29,714 d) Deferred tax charged directly to equity: - Equity raising costs 821 (986) — - Currency translation adjustment (952) 73 (362) (1) The Oklahoma US state tax jurisdiction computes income taxes on a direct accounting basis. |
OTHER INCOME (EXPENSES), NET (T
OTHER INCOME (EXPENSES), NET (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
OTHER INCOME (EXPENSES), NET | |
Schedule of other income (expense), net | 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Litigation settlements, net (1) (748) 1,200 — Insurance proceeds (2) — 2,375 — Escrow settlement from prior period property disposition (3) 1,000 — — Restructuring expenses (4) (56) (856) — Loss on foreign currency derivative — (390) — Write-off of unrecoverable cash call — — (1,621) Write-down of inventory to lower of cost or market — — (319) Other 261 (320) (300) Total other income, net 457 2,009 (2,240) (1) Litigation settlements, net recorded during the year ended 31 December 2017 includes the net impact of multiple favorable and unfavorable legal settlements, including an accrual for $1.0 million related to the Company’s 2013 sale of its non-operated North Dakota properties. In August 2015, the Buyer filed a lawsuit against the Company seeking payment for costs not included by the Buyer in the final post-closing settlement. In August 2017, a jury ruled in favor of the Buyer. The Company is currently appealing the decision, but has established a liability for such damages. During 2016, the Company was awarded a cash settlement of $1.2 million from litigation against a third party contractor for damages to a well that occurred in 2014. As part of the litigation settlement, the Company was also awarded $0.6 million for reimbursement of legal costs incurred (recorded to general and administrative expenses on the consolidated statement of profit or loss). (2) During 2016, the Company received insurance proceeds of $2.4 million related to a well control incident in 2014. (3) During 2017, the Company received a cash payout of $1.0 million from an escrow holding drilling commitment related funds related to properties sold by the Company in 2014. There had previously been uncertainty as to whether the drilling commitments would be met and to whom the funds would be paid to, and was therefore unrecognized in 2014. (4) In January 2016, the Company restructured its corporate organization and reduced its headcount by approximately 30% in order to reduce its cash operating costs in response to the lower oil price environment. Restructuring costs for the year ended 31 December 2016 included $0.4 million in employee severance costs and $0.5 million in office lease-related costs for certain office space that is expected to be no longer used as a result of office space consolidation. The office-lease-related costs represent the Company’s future obligations under the operating leases, net of anticipated sublease income. See also Note 23. |
KEY MANAGEMENT PERSONNEL COMP52
KEY MANAGEMENT PERSONNEL COMPENSATION (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
KEY MANAGEMENT PERSONNEL COMPENSATION. | |
Summary of total remuneration paid to Directors and Key Management Personnel | 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Short term wages and benefits 1,444 1,298 1,467 Share-based payments (equity or cash settled) (1) 1,429 2,025 2,271 Post-employment benefit 53 49 52 2,926 3,372 3,790 (1) The 2014 short-term incentive bonus (“STI”) granted to KMP, excluding the Managing Director, was granted by the Board of Directors in 2015 and paid out in the form of RSUs, which vested immediately. The associated expense is included in 2015 share-based payments in the table above. The 2014 STI to the Managing Director was approved by shareholders in 2016 and paid out in the form of RSUs with immediate vesting. The associated expense is included in 2016 share based payments in the table above. |
AUDITORS' REMUNERATION (Tables)
AUDITORS' REMUNERATION (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
AUDITORS’ REMUNERATION. | |
Schedule of auditors' remuneration | 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Amounts paid or payable to the auditor for: Auditing or review of the financial report (1) 485 461 463 Professional services related to filing of various Forms with the US Securities and Exchange Commission — — 13 Taxation services provided by the practice of auditor — — 61 Total remuneration of the auditor 485 461 537 (1) The 2016 amount includes $0.4 million paid to the Company’s former auditor, Ernst & Young, who provided audit services for the year ended 31 December 2015. The Company paid $0.1 million in 2016 to Deloitte Touche Tohmatsu Limited as its auditor for the year ended 31 December 2016. |
EARNINGS (LOSS) PER SHARE (EP54
EARNINGS (LOSS) PER SHARE (EPS) (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
EARNINGS (LOSS) PER SHARE (EPS) | |
Schedule of earnings per share | 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 Loss for periods used to calculate basic and diluted EPS (22,435) (45,694) (263,835) Number Number Number of shares of shares of shares a) -Weighted average number of ordinary shares outstanding during the period used in calculation of basic EPS(1) 1,251,338,659 870,582,898 552,847,289 b) -Incremental shares related to options and restricted share units(2) — — — c) -Weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS 1,251,338,659 870,582,898 552,847,289 (1) Calculation excludes approximately 1.5 million ordinary shares held in escrow as at 31 December 2017, 2016 and 2015. The shares were issued as part of the NSE acquisition in 2015 and are expected to be returned to the Company in satisfaction of certain working capital adjustments. (2) Incremental shares related to restricted share units were excluded from 31 December 2017, 2016 and 2015 weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS as the outstanding shares would be anti-dilutive to the loss per share calculation for the period then ended. |
TRADE AND OTHER RECEIVABLES (Ta
TRADE AND OTHER RECEIVABLES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
TRADE AND OTHER RECEIVABLES. | |
Schedule of trade and other receivables | 2017 2016 Year ended 31 December US$’000 US$’000 Oil, natural gas and NGL sales 2,604 8,201 Joint interest billing receivables 930 1,545 Commodity hedge contract receivables — 37 Other 432 3 Total trade and other receivables 3,966 9,786 |
DERIVATIVE FINANCIAL INSTRUME56
DERIVATIVE FINANCIAL INSTRUMENTS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
DERIVATIVE FINANCIAL INSTRUMENTS | |
Schedule of derivative financial instruments | 2017 2016 Year ended 31 December US$’000 US$’000 FINANCIAL ASSETS : Current Derivative financial instruments — commodity contracts 383 — Non-current Derivative financial instruments — commodity contracts 223 279 Total financial assets 606 279 FINANCIAL LIABILITIES : Current Derivative financial instruments — commodity contracts 5,618 4,579 Non-current Derivative financial instruments — commodity contracts 3,728 3,215 Total financial liabilities 9,346 7,794 |
ASSETS HELD FOR SALE (Table)
ASSETS HELD FOR SALE (Table) | 12 Months Ended |
Dec. 31, 2017 | |
ASSETS HELD FOR SALE | |
Schedule of assets held for sale | 2017 2016 Year ended 31 December US$’000 US$’000 Eagle Ford - Dimmit County oil and gas assets 61,064 — Mississippian/Woodford oil and gas assets — 18,309 Total assets held for sale 61,064 18,309 Restoration provision associated with held for sale developed assets 1,064 941 Total liabilities related to assets held for sale 1,064 941 |
FAIR VALUE MEASUREMENT (Tables)
FAIR VALUE MEASUREMENT (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
FAIR VALUE MEASUREMENT | |
Schedule of financial assets and liabilities measured at fair value . | Consolidated 31 December 2017 (US$’000) Level 1 Level 2 Level 3 Total Assets measured at fair value Derivative commodity contracts — 606 — 606 Liabilities measured at fair value Derivative commodity contracts — (9,346) — (9,346) Net fair value — (8,740) — (8,740) Consolidated 31 December 2016 (US$’000) Level 1 Level 2 Level 3 Total Assets measured at fair value Derivative commodity contracts — 279 — 279 Liabilities measured at fair value Derivative commodity contracts — (7,794) — (7,794) Net fair value — (7,515) — (7,515) |
OTHER CURRENT ASSETS (Tables)
OTHER CURRENT ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
OTHER CURRENT ASSETS. | |
Summary of other current assets | 2017 2016 Year ended 31 December US$’000 US$’000 Oil inventory on hand, lesser of cost or net realizable value 908 517 Equipment inventory, lesser of cost or net realizable value 1,479 1,721 Prepaid expenses 915 1,205 Other 170 635 Total other current assets 3,472 4,078 |
DEVELOPMENT AND PRODUCTION AS60
DEVELOPMENT AND PRODUCTION ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
DEVELOPMENT AND PRODUCTION ASSETS. | |
Schedule of development, production assets and movements in carrying amounts | 2017 2016 Year ended 31 December US$’000 US$’000 Costs carried forward in respect of areas of interest in: Development and production assets, at cost: Producing assets 778,735 838,792 Wells-in-progress 954 4,997 Undeveloped assets 31,580 30,119 -Development and production assets, at cost: 811,269 873,908 Accumulated depletion (277,098) (258,613) Accumulated impairment (136,643) (258,277) Total development and production expenditure 397,528 357,018 Less amount classified as asset held for sale (1) (58,732) (18,309) Total Development and Production Expenditure, net of assets held for sale 338,796 338,709 a) Movements in carrying amounts: Development expenditure Balance at the beginning of the period 338,709 250,922 Amounts capitalised during the period 115,120 57,893 Fair value of assets acquired — 23,873 Revision to restoration provision 1,550 3,238 Depletion expense (57,851) (47,490) Impairment expense — (3,409) Development and production assets sold during the period — (5,030) Reclassifications from assets held for sale (2) — 77,021 Reclassifications to assets held for sale (1) (58,732) (18,309) Balance at end of period 338,796 338,709 (1) In 2017, the Company committed to a plan to sell its interests in Dimmit County, Texas. Balance reflects amount transferred to assets held for sale before impairment (see Note 19). (2) |
EXPLORATION AND EVALUATION EX61
EXPLORATION AND EVALUATION EXPENDITURE (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
EXPLORATION AND EVALUATION EXPENDITURE | |
Schedule of exploration and evaluation expenditure | 2017 2016 Year ended 31 December US$’000 US$’000 Costs carried forward in respect of areas of interest in: Exploration and evaluation phase, at cost 185,819 176,550 Provision for impairment (143,093) (142,184) Total exploration and evaluation expenditures 42,726 34,366 Less amount classified as asset held for sale (1) (7,747) — Total Exploration and Evaluation Expenditure, net of assets held for sale 34,979 34,366 a) Movements in carrying amounts: Exploration and evaluation Balance at the beginning of the period 34,366 26,323 Amounts capitalised during the period 8,528 4,429 Exploration costs expensed — (30) Exploration tenements sold during the period — (2,096) Impairment expense (168) (7,871) Reclassifications from assets held for sale (2) — 13,611 Reclassifications to assets held for sale (1) (7,747) — Balance at end of period 34,979 34,366 (1) (2) |
IMPAIRMENT OF ASSETS (Tables)
IMPAIRMENT OF ASSETS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
IMPAIRMENT OF ASSETS | |
Schedule of future prices ($/bbl) used for VIU and FVLCS calculation | 2023 and 2018 2019 2020 2021 2022 thereafter $ 60.00 $ 62.50 $ 65.00 $ 67.50 $ 70.00 $ 75.00 |
Schedule of Recoverable amounts and resulting impairment expense | Recoverable 31 December 2017 Carrying costs amount Impairment (1) Cash-generating unit US$’000 US$’000 US$’000 Assets held for sale - Dimmit County 66,479 61,064 5,415 31 December 2016 Cash-generating unit (2) Exploration and evaluation expenditures: Mississippian/Woodford 1,183 — 1,183 Cooper Basin 6,688 — 6,688 Total exploration and evaluation 7,871 — 7,871 Development and production assets: Mississippian/Woodford 21,693 18,309 3,384 Total development and production assets 21,693 18,309 3,384 31 December 2015 Cash-generating unit Exploration and evaluation expenditures: Eagle Ford 151,171 33,511 (117,660) Mississippian/Woodford 5,164 1,190 (3,974) Cooper Basin 7,436 5,234 (2,202) Total exploration and evaluation 163,771 39,935 (123,836) Development and production assets: Eagle Ford 431,796 308,083 (123,713) Mississippian/Woodford 77,940 19,859 (58,081) Total development and production assets 509,736 327,942 (181,794) (1) Total impairment expense for the year ended 31 December 2017 also included $0.2 million related to additional costs incurred at the Cooper Basin, which was fully impaired in 2016. (2) Total impairment expense for the year ended 31 December 2016 was $11.3 million, which was net of an adjustment to 2015 impairment expense of $1.1 million related to a vendor discount for well completion services obtained subsequent to the filing of the Company’s 2015 annual report. Total impairment expense was $10.2 million. (3) The 31 December 2015 table reflects the year-end impairment analysis. The Company also recorded impairment expense related to its Mississippian/Woodford development and production assets of $2.6 million and its exploration and evaluation assets of $13.4 million during the first half of the year ended 31 December 2015. |
PROPERTY AND EQUIPMENT (Tables)
PROPERTY AND EQUIPMENT (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
PROPERTY AND EQUIPMENT. | |
Schedule of property and equipment | 2017 2016 Year ended 31 December US$’000 US$’000 Property and equipment, at cost 3,628 3,146 Accumulated depreciation (2,382) (1,935) Total Property and Equipment 1,246 1,211 a) Movements in carrying amounts: Balance at the beginning of the period 1,211 1,382 Amounts capitalized during the period 659 355 Amounts disposed of during the period (122) (151) Depreciation expense (502) (375) Balance at end of period 1,246 1,211 |
TRADE AND OTHER PAYABLES AND 64
TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES | |
Schedule of trade, other payables and accrued expenses | 2017 2016 Year ended 31 December US$’000 US$’000 Oil and natural gas property and operating related 40,001 18,588 Administrative expenses, including salaries and wages 4,494 2,225 Accrued interest payable 3,057 2,761 Commodity derivative contract payables 550 — Total trade, other payables and accrued expenses 48,102 23,574 |
OTHER PROVISIONS (Tables)
OTHER PROVISIONS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
OTHER PROVISIONS. | |
Schedule of other provisions | 2017 2016 Year ended 31 December US$’000 US$’000 Balance at the beginning of the period (1) 6,025 — New provisions — 6,025 Changes in estimates (747) — Settlements (1,932) — Unwinding of discount 73 — Reclassification from provisions to accrued liabilities (103) — Balance at end of period (1) 3,316 6,025 (1) |
CREDIT FACILITIES (Tables)
CREDIT FACILITIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
CREDIT FACILITIES. | |
Schedule of credit facilities | 2017 2016 US$'000 US$'000 Revolving Facility 67,000 66,750 Term Loan 125,000 125,000 Total Credit Facilities 192,000 191,750 Deferred financing fees, net of accumulated amortisation (2,690) (3,501) Total credit facilities, net of deferred financing fees 189,310 188,249 |
RESTORATION PROVISION (Tables)
RESTORATION PROVISION (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
RESTORATION PROVISION. | |
Schedule of restoration provision | 2017 2016 Year ended 31 December US$’000 US$’000 Balance at the beginning of the period 7,072 3,088 New provisions 938 305 Changes in estimates 663 2,956 Disposals and settlements (256) (114) New provisions assumed from acquisition — 894 Unwinding of discount 214 140 Reclassification from liabilities related to assets held for sale — 744 Reclassification to liabilities related to assets held for sale (1,064) (941) Balance at end of period 7,567 7,072 |
DEFERRED TAX ASSETS AND LIABI68
DEFERRED TAX ASSETS AND LIABILITIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
DEFERRED TAX ASSETS AND LIABILITIES. | |
Schedule of deferred tax assets and liabilities | 2017 2016 Year ended 31 December US$’000 US$’000 Net deferred tax assets: Share issuance costs — 1,534 Net operating loss carried forward — 2,636 Accrued interest — (2,756) Derivatives 1,884 — Development and production expenditure — 1,269 Other 111 Total net deferred tax assets 1,995 2,683 Deferred tax liabilities: Development and production expenditure (25,971) (10,654) Offset by deferred tax assets with legally enforceable right of set-off: Net operating loss carried forward 23,976 7,218 Accrued interest — 3,436 Total net deferred tax liabilities (1,995) — |
ISSUED CAPITAL (Tables)
ISSUED CAPITAL (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
ISSUED CAPITAL. | |
Schedule of total ordinary shares issued and outstanding | Number of Shares a) Ordinary Shares Total shares issued and outstanding at 31 December 2015 559,103,562 Shares issued during the year (1) 690,248,055 Total shares issued and outstanding at 31 December 2016 1,249,351,617 Shares issued during the year 3,897,911 Total shares issued and outstanding at 31 December 2017 1,253,249,528 Includes 1.5 million shares held in escrow related to the Company’s acquisition of NSE. |
Schedule of issued capital | 2017 2016 Year ended 31 December US$’000 US$’000 b) Issued Capital Beginning of the period 373,585 308,429 Shares issued in connection with: Share consideration paid in business combination — — Shares issued in conjunction with private placement (1) — 67,499 Total shares issued during the period — 67,499 Cost of capital raising during the period, net of tax benefit — (2,343) Derecognition of deferred tax asset (see note 7) (821) — Closing balance at end of period 372,764 373,585 (1) In 2016, the Company completed a 3‑tranche private placement of 685 million ordinary shares to professional and sophisticated investors for net proceeds of $64.2 million. The Company also recognized a tax benefit on the cost of capital of $1.0 million. |
Schedule of restricted share units outstanding | 2017 2016 Grant Date No. of RSUs No. of RSUs 15 April 2014 — 393,311 30 May 2014 — 167,997 28 May 2015 515,037 1,030,075 28 May 2015 (1) 1,545,113 1,545,113 24 June 2015 1,122,571 2,382,229 24 June 2015 (1) 2,267,879 2,267,879 1 August 2015 107,000 214,000 15 March 2016 (2) 6,824,951 6,824,950 27 May 2016 (2) 4,342,331 4,342,331 29 June 2016 (2) 1,633,763 3,614,316 15 August 2016 (2) — 800,000 15 August 2016 — 200,000 3 January 2017 187,500 — 17 February 2017 (2) 6,627,667 — 25 May 2017 (2) 3,724,191 — 23 October 2017 (2) 745,000 — 23 October 2017 1,500,000 — 29 December 2017 2,660,358 — Total RSUs outstanding 33,803,361 23,782,201 (1) (2) |
CAPITAL AND OTHER EXPENDITURE70
CAPITAL AND OTHER EXPENDITURE COMMITMENTS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
CAPITAL AND OTHER EXPENDITURE COMMITMENTS | |
Schedule of contractual commitments | Total Less than More than As at 31 December 2017 US$’000 1 year 1 — 5 years 5 years Cooper Basin capital commitments (1) 3,490 1,745 1,745 — Operating lease commitments (2) 2,446 1,050 1,396 — Employment commitments (3) 370 370 — — Total expenditure commitments 6,306 3,165 3,141 — As at 31 December 2016 Total US$’000 Less than 1 year 1 — 5 years More than 5 years Cooper Basin capital commitments (1) 3,373 1,687 1,686 — Drilling rig commitments (4) 1,085 1,085 — — Operating lease commitments (2) 4,123 1,353 2,267 503 Employment commitments (3) 740 370 370 — Total expenditure commitments 9,321 4,495 4,323 503 (1) (2) (3) (4) |
CASH FLOW INFORMATION (Tables)
CASH FLOW INFORMATION (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
CASH FLOW INFORMATION | |
Schedule of cash flow information | 2017 2016 2015 Year ended 31 December US$’000 US$’000 US$’000 a) Reconciliation of cash flows from operations with income from ordinary activities after income tax Loss from ordinary activities after income tax (22,435) (45,694) (263,835) Adjustments to reconcile net profit to net operating cash flows: Depreciation and amortisation expense 58,361 48,147 94,584 Share-based compensation 2,076 2,524 4,100 Unrealised losses on derivatives 1,224 21,433 (3,444) Net loss (gain) on sale of non-current assets 1,461 — (790) Decrease in fair value of securities at fair value through the profit and loss — — 90 Impairment of development and production assets 5,583 10,203 321,918 Unsuccessful exploration and evaluation expense — 30 — Loss on debt extinguishment — — 1,151 Add: Interest expense and financing costs (disclosed in investing and financing activities) 12,676 12,219 9,418 Recognition (derecognition) of deferred tax assets on items directly within equity (821) 986 — Less: Gain from escrow settlement, insurance proceeds and litigation settlements (disclosed in investing activities) (2,200) (3,603) — Less: Loss on foreign currency derivative (disclosed in financing activities) — 390 — Other 541 21 2,240 Changes in assets and liabilities: - Decrease (increase) in current and deferred income tax 2,888 (826) (100,583) - Decrease (increase) in other current assets 72 (511) 2,742 - Decrease in trade and other receivables 5,241 2,009 7,007 - Increase (decrease) in trade and other payables 9,633 (5,080) (2,177) - Decrease in tax receivable 476 412 (6,522) - Decrease in non-current liability — — (1,430) Net cash provided by operating activities 74,776 42,660 64,469 |
SHARE BASED PAYMENTS (Tables)
SHARE BASED PAYMENTS (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
SHARE BASED PAYMENTS | |
Summary of restricted share units | Weighted Average Fair Number Value at Measurement of RSUs Date A$ Outstanding at 31 December 2014 2,964,177 0.93 Issued or Issuable 13,322,262 0.53 Converted to ordinary shares (3,805,789) 0.63 Forfeited (46,312) 0.93 Outstanding at 31 December 2015 12,434,338 0.55 Issued or Issuable (1) 18,267,192 0.18 Converted to ordinary shares (5,501,538) 0.54 Forfeited (1,417,791) 0.59 Outstanding at 31 December 2016 23,782,201 0.34 Issued or Issuable 15,757,216 0.09 Converted to ordinary shares (3,897,911) 0.43 Forfeited (1,838,145) 0.15 Outstanding at 31 December 2017 33,803,361 0.22 (1) Includes 1,275,000 of RSUs formally issued on the ASX in 2016 in conjunction with a 2015 option conversion. |
Schedule of RSUs granted | RSUs awarded during the year ended 31 December 2017: Fair Value at Measurement Date Grant Date Number of RSUs (Per RSU in US$) Vesting Conditions 3 January 2017 250,000 $ 0.22 25% after 90 days; then 25% on 3 January 2018, 2019 and 2020 9 January 2017 250,000 $ 0.24 25% after 90 days; then 25% on 9 January 2018, 2019 and 2020 2 February 2017 6,627,667 $ 0.12 0 % - 150% based on 3 year ATSR 25 May 2017 3,724,191 $ 0.05 0 % - 150% based on 3 year ATSR 23 October 2017 745,000 $ 0.03 0 % - 150% based on 3 year ATSR 23 October 2017 1,500,000 $ 0.05 25% after 90 days; then 25% on 23 October 2018, 2019 and 2020 29 December 2017 2,660,358 $ 0.07 33 % on 31 January 2018, 2019 and 2020 15,757,216 RSUs awarded during the year ended 31 December 2016: Fair Value at Measurement Date Grant Date Number of RSUs (Per RSU in US$) Vesting Conditions 15 March 2016 6,824,950 $ 0.15 0 % - 133% based on 3 year ATSR 27 May 2016 4,342,331 $ 0.10 0 % - 133% based on 3 year ATSR 27 May 2016 770,950 $ 0.12 100 % vested immediately 29 June 2016 3,853,961 $ 0.08 33 % on 1 January 2017, 2018 and 2019 15 August 2016 400,000 $ 0.11 50 % on 13 November 2016 and 50% on 11 February 2017 15 August 2016 800,000 $ 0.11 0 % - 133% based on 3 year ATSR 16,992,192 RSUs awarded during the year ended 31 December 2015: Fair Value at Measurement Date Grant Date Number of RSUs (Per RSU in US$) Vesting Conditions 27 April 2015 $ 25 % on 27 April 2016, 2017, 2018 and 2019 28 May 2015 1,545,113 $ 33 % on 31 January 2016, 2017 and 2018 28 May 2015 1,545,113 $ 0% - 200% based on 3 year total shareholder return as compared to peers 24 June 2015 4,267,002 $ 33 % on 31 January 2016, 2017 and 2018 24 June 2015 2,815,681 $ 0% - 200% based on 3 year total shareholder return as compared to peers 24 June 2015 2,809,479 $ 100 % vested upon issuance 1 September 2015 321,000 $ 33 % on 31 January 2016, 2017 and 2018 13,332,262 |
Schedule of deferred cash awards | Amount of Deferred Cash Awards Outstanding at 31 December 2014 — Granted — Vested and paid in cash — Forfeited — Outstanding at 31 December 2015 — Granted 2,079,879 Vested and paid in cash — Forfeited (31,681) Outstanding at 31 December 2016 2,048,198 Granted 1,998,675 Vested and paid in cash — Forfeited (1,744,228) Outstanding at 31 December 2017 2,302,645 |
FINANCIAL RISK MANAGEMENT (Tabl
FINANCIAL RISK MANAGEMENT (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
Disclosure of nature and extent of risks arising from financial instruments [line items] | |
Schedule of outstanding derivative positions | A summary of the Company’s outstanding derivative positions as at 31 December 2017 is below: Oil Derivatives (WTI/LLS) Weighted Average (1) Year Units (Bbls) Floor Ceiling 2018 891,000 $ 50.40 $ 56.86 2019 828,000 $ 50.56 $ 53.49 2020 108,000 $ 47.05 $ 52.50 Total 1,827,000 $ 50.28 $ 55.07 Gas Derivatives (HH/HSC) Weighted Average (1) Year Units (Mcf) Floor Ceiling 2018 2,106,000 $ 2.92 $ 3.24 2019 1,212,000 $ 2.78 $ 3.47 2020 216,000 $ 2.54 $ 2.93 Total 3,534,000 $ 2.85 $ 3.30 (1) |
Schedule of maturity analysis of commitments related to its financial liabilities | The Company has the following commitments related to its financial liabilities (US$’000): Less than More than Year ended 31 December 2017 Total 1 year 1 — 5 years 5 years Trade and other payables 9,051 9,051 — — Accrued expenses 39,051 39,051 — — Production prepayment 18,194 18,194 — — Provisions 3,316 1,158 2,158 — Credit facilities payments, including interest (1) 225,933 13,674 212,259 — Total 295,545 81,128 214,417 — Less than More than Year ended 31 December 2016 Total 1 year 1 — 5 years 5 years Trade and other payables 3,579 3,579 — — Accrued expenses 19,995 19,995 — — Provisions 6,025 2,726 3,299 — Credit facilities payments, including interest (1) 235,441 12,606 222,835 — Total 265,040 38,906 226,134 — (1) Assumes credit facilities are held to maturity. |
Commodity price risk | |
Disclosure of nature and extent of risks arising from financial instruments [line items] | |
Schedule of sensitivity analysis for commodity price risk and interest rate risk | 2017 2016 Year ended 31 December US$’000 US$’000 Effect on profit before tax Increase / (Decrease) Oil - improvement in US$ oil price of $10 per barrel (14,287) (12,813) - decline in US$ oil price of $10 per barrel 15,961 16,233 Gas - improvement in US$ gas price of $0.50 per mcf (1,254) (1,423) - decline in US$ gas price of $0.50 per mcf 1,504 1,306 |
Interest rate risk | |
Disclosure of nature and extent of risks arising from financial instruments [line items] | |
Schedule of sensitivity analysis for commodity price risk and interest rate risk | 2017 2016 Year ended 31 December US$’000 US$’000 Effect on profit (loss) before tax Increase / (Decrease) - increase in interest rates + 2% (3,663) (3,357) - decrease in interest rates - 2% 1,177 396 |
SUBSIDIARIES (Tables)
SUBSIDIARIES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
SUBSIDIARIES | |
The disclosure of significant subsidiaries | Name of Entity Place of Incorporation Percentage Owned Sundance Energy Inc. Colorado 100 Sundance Energy Oklahoma, LLC Delaware 100 SEA Eagle Ford, LLC Texas 100 Armadillo Eagle Ford Holdings, Inc.(1) Delaware 100 Armadillo E&P, Inc. Delaware 100 NSE PEL570 LTD Australia 100 (1) Entity was dissolved subsequent to 31 December 2017. |
UNAUDITED SUPPLEMENTAL OIL AN75
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES (Tables) | 12 Months Ended |
Dec. 31, 2017 | |
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |
Schedule of capitalised costs incurred in oil and gas production, exploration, and development activities | Year ended December 31, (in thousands) 2017 2016 2015 Property acquisition costs Proved $ 4,335 $ 23,873 $ 13,170 Unproved 1,244 2,815 15,495 Exploration costs 2,949 1,650 10,353 Development costs (1) 115,120 61,131 76,831 $ 123,648 $ 89,469 $ 115,849 (1) 2016 and 2015 development costs include $5.0 million and $16.6 million of costs associated with non-producing wells in progress as at December 31, 2016 and 2015, respectively. These wells in progress were either drilling, waiting on hydraulic fracturing or production testing at year-end. There were no wells in progress at December 31, 2017. |
Schedule of estimated reserve data | Natural Total Oil Oil Gas NGL Equivalents (MBbl) (MMcf) (MBbl) (MBoe) Total proved reserves: 31 December 2014 17,026 28,733 4,166 25,981 Revisions of previous estimates (3,491) (8,152) (1,218) (6,068) Extensions and discoveries 1,950 4,122 699 3,336 Purchases of reserves in-place 3,896 4,454 238 4,876 Production (1,829) (2,581) (393) (2,652) Sales of reserves in-place — — — — 31 December 2015 17,552 26,576 3,492 25,473 Revisions of previous estimates (1,397) 536 (833) (2,141) Extensions and discoveries 4,242 10,240 1,551 7,500 Purchases of reserves in-place 1,432 3,121 1,216 3,168 Production (1,412) (2,941) (332) (2,234) Sales of reserves in-place (1,976) (1,802) — (2,276) 31 December 2016 18,441 35,730 5,094 29,490 Revisions of previous estimates (1,778) (2,091) 154 (1,972) Extensions and discoveries 6,658 17,255 2,852 12,386 Purchases of reserves in-place 6,892 14,935 1,897 11,278 Production (1,800) (3,621) (324) (2,727) Sales of reserves in-place (426) (2,799) (483) (1,376) 31 December 2017 27,987 59,409 9,190 47,079 Proved developed reserves: 31 December 2015 6,379 13,205 1,998 10,578 31 December 2016 7,440 16,704 2,269 12,493 31 December 2017 8,987 21,078 3,244 15,744 Proved undeveloped reserves 31 December 2015 11,173 13,371 1,494 14,895 31 December 2016 11,001 19,026 2,825 16,997 31 December 2017 19,000 38,331 5,946 31,335 |
Summary of Standardized Measure | Year ended 31 December (in thousands) 2017 2016 2015 Cash inflows $ 1,866,923 $ 892,576 $ 936,041 Production costs (667,438) (307,907) (246,277) Development costs (516,243) (274,384) (308,253) Income tax expense (35,933) — (1,602) Net cash flow 647,309 310,285 379,909 10% annual discount rate (280,562) (151,146) (198,142) Standardized measure of discounted future net cash flow $ 366,747 $ 159,139 $ 181,767 |
Summary of principal sources of change in the Standardized Measure | Year ended 31 December (in thousands) 2017 2016 2015 Standardized Measure, beginning of period $ 159,139 $ 181,767 $ 435,506 Sales, net of production costs (75,370) (49,496) (67,693) Net change in sales prices, net of production costs 7,899 (62,670) (369,770) Extensions and discoveries, net of future production and development costs 94,151 3,603 11,609 Changes in future development costs 17,128 5,331 28,092 Previously estimated development costs incurred during the period 51,414 45,012 31,007 Revision of quantity estimates (20,598) 9,762 (91,440) Accretion of discount 15,914 18,217 53,173 Change in income taxes (14,492) 402 95,827 Purchases of reserves in-place 88,280 17,004 442 Sales of reserves in-place (7,544) 845 — Change in production rates and other 50,826 (10,638) 55,014 Standardized Measure, end of period $ 366,747 $ 159,139 $ 181,767 The 2017 change in production rates and other is primarily related to the Company accelerating the recoveries of reserves. |
Schedule of average prices used in determining the Standardized Measure | Year ended 31 December 2017 2016 2015 Oil price per Bbl $ 52.60 $ 42.02 $ 48.47 Gas price per Mcf $ 3.17 $ 1.22 $ 1.27 NGL price per Bbl $ 22.47 $ 14.55 $ 14.80 |
STATEMENT OF SIGNIFICANT ACCO76
STATEMENT OF SIGNIFICANT ACCOUNTING POLICIES (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Statement of significant accounting policies | |||
Reversal of impairment loss | $ 0 | $ 0 | $ 0 |
Capitalisation of borrowing cost | $ 1,400 | $ 1,100 | |
Vesting period | 3 years | ||
Contractual obligations related to its non-cancelable leases and drilling rig contracts | $ 2,400 | ||
Bottom of range | |||
Statement of significant accounting policies | |||
Asset depreciation (as a percent) | 5.00% | ||
Measurement period | 1 year | ||
Top of range | |||
Statement of significant accounting policies | |||
Asset depreciation (as a percent) | 33.00% | ||
Measurement period | 3 years |
BUSINESS COMBINATIONS (Details)
BUSINESS COMBINATIONS (Details) $ in Thousands, shares in Millions, EquityInstruments in Millions, $ in Millions | 1 Months Ended | 5 Months Ended | 12 Months Ended | |||||
Aug. 31, 2015USD ($)aEquityInstrumentsitem | Dec. 31, 2016USD ($)shares | Dec. 31, 2017USD ($) | Dec. 31, 2017AUD ($)shares | Dec. 31, 2017USD ($)shares | Dec. 19, 2016USD ($)aitem | Jul. 29, 2016USD ($)aitem | Dec. 31, 2015shares | |
Purchase price: | ||||||||
Revenue of combined entity | $ 72,000 | |||||||
Ordinary shares | ||||||||
Purchase price: | ||||||||
Shares held in escrow | shares | 1.5 | 1.5 | 1.5 | 1.5 | ||||
Cooper Basin capital commitments | ||||||||
BUSINESS COMBINATIONS | ||||||||
Capital commitments | $ 3,373 | $ 3,490 | ||||||
Cooper Basin capital commitments | Top of range | ||||||||
BUSINESS COMBINATIONS | ||||||||
Capital commitments | $ 10.6 | |||||||
Eagle Ford | ||||||||
Purchase price: | ||||||||
Increase in revenue of combined entity | 5,300 | |||||||
Decrease in profit loss before tax of combined entity | (1,200) | |||||||
Loss before income tax of combined entity | $ (42,800) | |||||||
Eagle Ford acquisition one | ||||||||
BUSINESS COMBINATIONS | ||||||||
Net acres | a | 5,050 | |||||||
Gross producing wells | item | 26 | |||||||
Net producing wells | item | 9.1 | |||||||
Fair value of assets acquired: | ||||||||
Development and production assets | $ 16,628 | |||||||
Restoration provision | (747) | |||||||
Net assets acquired | 15,881 | |||||||
Purchase price: | ||||||||
Cash consideration | 15,881 | |||||||
Total consideration paid | $ 15,881 | |||||||
Revenue | 2,400 | |||||||
Net income excluding the impact of income taxes | $ 400 | |||||||
Eagle Ford acquisition two | ||||||||
BUSINESS COMBINATIONS | ||||||||
Net acres | a | 130 | |||||||
Gross producing wells | item | 23 | |||||||
Net producing wells | item | 1.5 | |||||||
Operated gross producing wells | item | 12 | |||||||
Operated net producing wells | item | 1 | |||||||
Fair value of assets acquired: | ||||||||
Development and production assets | $ 7,348 | |||||||
Restoration provision | (118) | |||||||
Net assets acquired | 7,230 | |||||||
Purchase price: | ||||||||
Cash consideration | 7,230 | |||||||
Total consideration paid | $ 7,230 | |||||||
Acquisition in 2015 | ||||||||
Purchase price: | ||||||||
Total consideration paid | $ 16,400 | |||||||
NSE U.S (Eagle Ford) | ||||||||
BUSINESS COMBINATIONS | ||||||||
Net acres | a | 5,500 | |||||||
Gross producing wells | item | 7 | |||||||
Oil wells drilled but not yet completed | item | 2 | |||||||
Oil wells drilled and subsequently completed | item | 1 | |||||||
Purchase price: | ||||||||
Cash consideration | $ 15,000 | |||||||
Issuance of shares | EquityInstruments | 6 | |||||||
Acquired cash | $ 200 | |||||||
Cooper Basin | ||||||||
BUSINESS COMBINATIONS | ||||||||
Working interest percentage | 17.50% |
DISPOSALS OF NON CURRENT ASSTES
DISPOSALS OF NON CURRENT ASSTES (Details) $ in Thousands | May 01, 2017USD ($) | May 31, 2017USD ($) | Dec. 31, 2016USD ($)a | Apr. 30, 2017USD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Aug. 01, 2016USD ($) |
DISPOSALS OF NON CURRENT ASSETS | ||||||||
Loss on sale of non-current assets | $ 1,461 | $ (790) | ||||||
Liabilities related to assets held for sale | $ 941 | 1,064 | $ 941 | |||||
Cash proceeds from sale of non-current assets | $ 15,348 | $ 7,141 | $ 41 | |||||
Eagle Ford acreage | Texas | ||||||||
DISPOSALS OF NON CURRENT ASSETS | ||||||||
Loss on sale of non-current assets | $ 0 | |||||||
Number of gross acres divested | a | 3,336 | |||||||
Number of net acres divested | a | 2,709 | |||||||
Cash proceeds from sale of non-current assets | $ 7,100 | |||||||
Mississippian/Woodford | ||||||||
DISPOSALS OF NON CURRENT ASSETS | ||||||||
Loss on sale of non-current assets | $ 1,300 | |||||||
Liabilities related to assets held for sale | $ 900 | |||||||
Revenue, net of production taxes and operating expenses from business unit | $ 1,400 | |||||||
Sundance Energy Oklahoma, LLC | ||||||||
DISPOSALS OF NON CURRENT ASSETS | ||||||||
Sales price of noncurrent assets | $ 18,500 |
REVENUE (Details)
REVENUE (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
REVENUE. | |||
Oil revenue | $ 89,136 | $ 57,296 | $ 82,949 |
Natural gas revenue | 8,743 | 4,937 | 4,720 |
Natural gas liquid ("NGL") revenue | 6,520 | 4,376 | 4,522 |
Total revenue | $ 104,399 | $ 66,609 | $ 92,191 |
LEASE OPERATING EXPENSES (Detai
LEASE OPERATING EXPENSES (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
LEASE OPERATING EXPENSES | |||
Lease operating expense | $ (17,127) | $ (11,259) | $ (16,667) |
Workover expense | (5,289) | (1,678) | (1,788) |
Total lease operating expense | $ (22,416) | $ (12,937) | $ (18,455) |
GENERAL AND ADMINISTRATIVE EX81
GENERAL AND ADMINISTRATIVE EXPENSES (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
GENERAL AND ADMINISTRATIVE EXPENSES | |||
Employee benefits expense, including salaries and wages, net of capitalised overhead | $ (4,088) | $ (3,260) | $ (4,849) |
Share based payments expense | (1,868) | (2,748) | (4,100) |
Legal and other professional fees | (6,330) | (2,085) | (3,347) |
Corporate fees | (1,937) | (1,762) | (1,986) |
Rent | (632) | (669) | (993) |
Regulatory expenses | (314) | (279) | (203) |
Transaction related costs | (2,118) | (323) | (540) |
Other expenses | (1,058) | (984) | (1,158) |
Total general and administrative expenses | (18,345) | (12,110) | (17,176) |
Capitalised overhead | $ 2,700 | $ 2,100 | $ 3,000 |
INCOME TAX EXPENSE (Details)
INCOME TAX EXPENSE (Details) $ in Millions | 12 Months Ended | ||
Dec. 31, 2018 | Dec. 31, 2017USD ($)item | Dec. 31, 2016USD ($) | |
INCOME TAX EXPENSE | |||
Income tax expense from derecognizing assets | $ 7.1 | ||
Income tax expense from derecognizing assets charged directly to equity | $ 0.2 | $ (1) | |
Applicable tax rate | 30.00% | ||
Decrease to deferred tax assets | $ 18.8 | ||
Reclassification of AMT credit from unrecognized tax asset to income tax receivable - noncurrent | $ 4.7 | ||
Number of highly compensated executive officers | item | 3 | ||
Percentage of bonus depreciation on self-constructed assets | 100.00% | ||
Forecast | |||
INCOME TAX EXPENSE | |||
Applicable tax rate | 21.00% | ||
Year 1 | |||
INCOME TAX EXPENSE | |||
Income tax receivable - noncurrent to be claimed on tax filling (as a percent) | 50 | ||
1-2 Years | |||
INCOME TAX EXPENSE | |||
Income tax receivable - noncurrent to be claimed on tax filling (as a percent) | 25 | ||
2-3 Years | |||
INCOME TAX EXPENSE | |||
Income tax receivable - noncurrent to be claimed on tax filling (as a percent) | 12.5 | ||
3-4 Years | |||
INCOME TAX EXPENSE | |||
Income tax receivable - noncurrent to be claimed on tax filling (as a percent) | 12.5 | ||
Top of range | |||
INCOME TAX EXPENSE | |||
Applicable tax rate | 35.00% | ||
Performance-based compensation | $ 1 |
INCOME TAX EXPENSE - Summary of
INCOME TAX EXPENSE - Summary of income tax expense (benefit) (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($)item | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
INCOME TAX EXPENSE | |||
Current tax expense (benefit) | $ (4,688) | $ 1,563 | $ (6,191) |
Deferred tax expense | 2,815 | 142 | (100,947) |
Loss before income tax | (24,308) | (43,989) | (370,973) |
Prima facie tax expense at the Group’s statutory income tax rate of 30% | (7,293) | (13,197) | (111,292) |
Difference of tax rate in US controlled entities | (53) | (2,161) | (20,447) |
Impact of direct accounting from US controlled entities | (8) | (98) | (3,165) |
Share based compensation | 781 | 539 | 747 |
Other allowable items | (83) | 314 | 77 |
Refundable AMT Credits | (4,688) | ||
Change in unrecognized tax assets | 9,471 | 16,308 | 27,026 |
Change in unrecognized tax assets due to Tax Reform | (18,821) | ||
Total tax expense (income) | (1,873) | 1,705 | (107,138) |
Unused tax losses and temporary differences for which no deferred tax asset has been recognised at 30% | 36,672 | 46,022 | 29,714 |
Deferred tax charged directly to equity | $ 200 | (1,000) | |
Deferred tax benefit | 2,683 | ||
Applicable tax rate | 30.00% | ||
United States | |||
INCOME TAX EXPENSE | |||
Tax effect from change in tax rate | $ 18,821 | ||
Number of tax entities consolidated | item | 2 | ||
US controlled entities | |||
INCOME TAX EXPENSE | |||
Tax effect from change in tax rate | (84) | ||
Equity raising costs | |||
INCOME TAX EXPENSE | |||
Deferred tax charged directly to equity | $ 821 | (986) | |
Currency translation adjustment | |||
INCOME TAX EXPENSE | |||
Deferred tax charged directly to equity | $ (952) | $ 73 | $ (362) |
OTHER INCOME (EXPENSES), NET (D
OTHER INCOME (EXPENSES), NET (Details) - USD ($) $ in Thousands | 1 Months Ended | 12 Months Ended | ||
Jan. 31, 2016 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | $ 457 | $ 2,009 | $ (2,240) | |
Legal and other professional fees expense | 6,330 | 2,085 | 3,347 | |
Litigation settlements, net | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | (748) | 1,200 | ||
Insurance proceeds | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | 2,375 | |||
Escrow settlement from prior period property disposition | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | 1,000 | |||
Litigation settlement | General and administrative expenses | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Legal and other professional fees expense | (600) | |||
Restructuring expenses | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | (56) | (856) | ||
Reduction in number of employees (as a percent) | 30.00% | |||
Restructuring expenses | Employee severance costs | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | $ (400) | |||
Restructuring expenses | Office-lease-related costs | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | $ (500) | |||
Loss on foreign currency derivative | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | (390) | |||
Write-off of unrecoverable cash call | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | (1,621) | |||
Write-down of inventory to lower of cost or market | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | (319) | |||
Other | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | $ 261 | $ (320) | (300) | |
Reimbursement of legal costs | ||||
OTHER INCOME (EXPENSE), NET. | ||||
Total other income, net | $ 600 |
KEY MANAGEMENT PERSONNEL COMP85
KEY MANAGEMENT PERSONNEL COMPENSATION (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
KEY MANAGEMENT PERSONNEL COMPENSATION. | |||
Short term wages and benefits | $ 1,444 | $ 1,298 | $ 1,467 |
Share based payments (equity or cash settled) | 1,429 | 2,025 | 2,271 |
Post-employment benefit | 53 | 49 | 52 |
Total directors and key management personnel compensation | $ 2,926 | $ 3,372 | $ 3,790 |
KEY MANAGEMENT PERSONNEL COMP86
KEY MANAGEMENT PERSONNEL COMPENSATION - Grants and awards as compensation (Details) | 12 Months Ended | ||
Dec. 31, 2017USD ($)item | Dec. 31, 2016USD ($)item | Dec. 31, 2015USD ($)item | |
Bottom of range | |||
KEY MANAGEMENT PERSONNEL COMPENSATION. | |||
Measurement period | 1 year | ||
Top of range | |||
KEY MANAGEMENT PERSONNEL COMPENSATION. | |||
Measurement period | 3 years | ||
Restricted stock units (RSUs) | |||
KEY MANAGEMENT PERSONNEL COMPENSATION. | |||
Measurement period | 3 years | ||
Deferred cash award | Bottom of range | |||
KEY MANAGEMENT PERSONNEL COMPENSATION. | |||
Measurement period | 1 year | ||
Deferred cash award | Top of range | |||
KEY MANAGEMENT PERSONNEL COMPENSATION. | |||
Measurement period | 3 years | ||
Directors and key management personnel | Restricted stock units (RSUs) | |||
KEY MANAGEMENT PERSONNEL COMPENSATION. | |||
Number of units awarded as compensation | item | 7,835,513 | 9,906,997 | 7,426,596 |
Total fair value of units granted | $ 500,000 | $ 1,200,000 | $ 3,800,000 |
Measurement period | 3 years | ||
Directors and key management personnel | Deferred cash award | |||
KEY MANAGEMENT PERSONNEL COMPENSATION. | |||
Deferred cash award, amount granted | $ 1,138,503 | 1,264,998 | |
Deferred cash award, amount forfeited | $ 379,501 | $ 632,499 |
AUDITORS' REMUNERATION (Details
AUDITORS' REMUNERATION (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Auditors Remuneration [Line Items] | |||
Auditing or review of the financial report | $ 485 | $ 461 | $ 463 |
Professional services related to filing of various Forms with the US Securities and Exchange Commission | 13 | ||
Taxation services provided by the practice of auditor | 61 | ||
Total remuneration of the auditor | $ 485 | 461 | $ 537 |
Auditors' remuneration, former auditors | |||
Auditors Remuneration [Line Items] | |||
Auditing or review of the financial report | 400 | ||
Auditors' remuneration, current auditor | |||
Auditors Remuneration [Line Items] | |||
Auditing or review of the financial report | $ 100 |
EARNINGS (LOSS) PER SHARE (EP88
EARNINGS (LOSS) PER SHARE (EPS) (Details) - USD ($) $ in Thousands | 4 Months Ended | 12 Months Ended | ||
Apr. 30, 2018 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
EARNINGS (LOSS) PER SHARE (EPS) | ||||
Loss from ordinary activities after income tax | $ (22,435) | $ (45,694) | $ (263,835) | |
Weighted average number of ordinary shares outstanding during the period used in calculation of basic EPS | 1,251,338,659 | 870,582,898 | 552,847,289 | |
Weighted average number of ordinary shares outstanding during the period used in calculation of diluted EPS | 1,251,338,659 | 870,582,898 | 552,847,289 | |
Ordinary shares issued | ||||
EARNINGS (LOSS) PER SHARE (EPS) | ||||
Number of additional ordinary shares issued | 5,614,447,268 | |||
Equity raise | $ 260,000 | |||
Ordinary shares | ||||
EARNINGS (LOSS) PER SHARE (EPS) | ||||
Shares held in escrow | 1,500,000 | 1,500,000 | 1,500,000 |
TRADE AND OTHER RECEIVABLES (De
TRADE AND OTHER RECEIVABLES (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
TRADE AND OTHER RECEIVABLES | ||
Total trade and other receivables | $ 3,966 | $ 9,786 |
Oil, Natural Gas and NGL sales | ||
TRADE AND OTHER RECEIVABLES | ||
Total trade and other receivables | 2,604 | 8,201 |
Joint interest billing receivables | ||
TRADE AND OTHER RECEIVABLES | ||
Total trade and other receivables | 930 | 1,545 |
Commodity derivative contract receivables | ||
TRADE AND OTHER RECEIVABLES | ||
Total trade and other receivables | 37 | |
Other | ||
TRADE AND OTHER RECEIVABLES | ||
Total trade and other receivables | $ 432 | $ 3 |
DERIVATIVE FINANCIAL INSTRUME90
DERIVATIVE FINANCIAL INSTRUMENTS (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
DERIVATIVE FINANCIAL INSTRUMENTS | ||
Current derivative financial assets | $ 383 | |
Non-current derivative financial assets | 223 | $ 279 |
Total financial assets | 606 | 279 |
Current derivative financial liabilities | 5,618 | 4,579 |
Non-current derivative financial liabilities | 3,728 | 3,215 |
Total financial liabilities | $ 9,346 | $ 7,794 |
ASSETS HELD FOR SALE (Details)
ASSETS HELD FOR SALE (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
PROPERTY AND EQUIPMENT | ||
Total assets held for sale | $ 61,064 | $ 18,309 |
Total liabilities held for sale | 1,064 | 941 |
Restoration provision | ||
PROPERTY AND EQUIPMENT | ||
Total liabilities held for sale | 1,064 | 941 |
Eagle Ford assets | ||
PROPERTY AND EQUIPMENT | ||
Total assets held for sale | $ 61,064 | |
Mississippian/Woodward assets | ||
PROPERTY AND EQUIPMENT | ||
Total assets held for sale | $ 18,309 |
FAIR VALUE MEASUREMENT (Details
FAIR VALUE MEASUREMENT (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
FAIR VALUE MEASUREMENT | ||
Assets measured at fair value | $ 454,618 | $ 432,088 |
Liabilities measured at fair value | (277,267) | (234,265) |
Net fair value | 177,351 | 197,823 |
Transfers of financial assets from level 1 to 2 | 0 | 0 |
Transfers of financial assets from level 2 to 1 | 0 | 0 |
Transfers of financial assets into 3 | 0 | 0 |
Transfers of financial assets from 3 | 0 | 0 |
Transfers of financial liabilities from level 1 to 2 | 0 | 0 |
Transfers of financial liabilities from level 2 to 1 | 0 | 0 |
Transfers of financial liabilities into 3 | 0 | 0 |
Transfers of financial liabilities from 3 | 0 | 0 |
Principal debt outstanding | 192,000 | 191,750 |
Term loan | ||
FAIR VALUE MEASUREMENT | ||
Principal debt outstanding | 125,000 | |
Fair value of term loan | 119,000 | |
Revolving facility | ||
FAIR VALUE MEASUREMENT | ||
Principal debt outstanding | $ 67,000 | 66,750 |
Bottom of range | Floating interest rate | ||
FAIR VALUE MEASUREMENT | ||
Adjustment to interest rate basis | 2.00% | |
Top of range | Floating interest rate | ||
FAIR VALUE MEASUREMENT | ||
Adjustment to interest rate basis | 3.00% | |
At fair value | ||
FAIR VALUE MEASUREMENT | ||
Net fair value | $ (8,740) | (7,515) |
At fair value | Derivatives | ||
FAIR VALUE MEASUREMENT | ||
Liabilities measured at fair value | (9,346) | (7,794) |
At fair value | Level 2 | ||
FAIR VALUE MEASUREMENT | ||
Net fair value | (8,740) | (7,515) |
At fair value | Level 2 | Derivatives | ||
FAIR VALUE MEASUREMENT | ||
Liabilities measured at fair value | (9,346) | (7,794) |
At fair value | Derivatives | ||
FAIR VALUE MEASUREMENT | ||
Assets measured at fair value | 606 | 279 |
At fair value | Derivatives | Level 2 | ||
FAIR VALUE MEASUREMENT | ||
Assets measured at fair value | $ 606 | $ 279 |
OTHER CURRENT ASSTES (Details)
OTHER CURRENT ASSTES (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
OTHER CURRENT ASSETS. | ||
Oil inventory on hand, lesser of cost or net realizable value | $ 908 | $ 517 |
Equipment inventory, lesser of cost or net realizable value | 1,479 | 1,721 |
Prepaid expenses | 915 | 1,205 |
Other | 170 | 635 |
Total other current assets | $ 3,472 | $ 4,078 |
DEVELOPMENT AND PRODUCTION AS94
DEVELOPMENT AND PRODUCTION ASSETS (Details) - USD ($) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | |
Development and production assets, at cost: | |||||
Producing assets | $ 778,735 | $ 838,792 | |||
Wells-in-progress | 954 | 4,997 | |||
Undeveloped assets | 31,580 | 30,119 | |||
Development and production assets, at cost: | 811,269 | 873,908 | |||
Accumulated depletion | (277,098) | (258,613) | |||
Accumulated impairment | (136,643) | (258,277) | |||
Total development and production expenditure | 397,528 | 357,018 | |||
Less amount classified as asset held for sale | (61,064) | (18,309) | |||
Total Development and Production Expenditure, net of assets held for sale | $ 338,709 | $ 250,922 | $ 250,922 | $ 338,796 | $ 338,709 |
Development expenditure | |||||
Balance at the beginning of the period | 338,709 | 250,922 | |||
Amounts capitalised during the period | 115,120 | 57,893 | |||
Fair value of assets acquired | 23,873 | ||||
Revision to restoration provision | 1,550 | 3,238 | |||
Depreciation and amortisation expense | (58,361) | (48,147) | (94,584) | ||
Impairment expense (adjustment) | 5,583 | 10,203 | 321,918 | ||
Development and production assets sold during the period | (5,030) | ||||
Balance at end of period | 338,796 | 338,709 | $ 250,922 | ||
Capitalization of borrowing cost as part of oil and gas properties | 1,400 | 1,100 | |||
Interest amount capitalized (as a percent) | 10.20% | 6.70% | |||
Development and production assets | |||||
Development and production assets, at cost: | |||||
Less amount classified as asset held for sale | $ (58,732) | $ (18,309) | |||
Development expenditure | |||||
Depreciation and amortisation expense | (57,851) | (47,490) | |||
Impairment expense (adjustment) | (3,409) | ||||
Reclassifications from assets held for sale | 77,021 | ||||
Reclassifications to assets held for sale | $ (58,732) | $ (18,309) | |||
Eagle Ford | Development and production assets | |||||
Development expenditure | |||||
Percentage of assets classified as held for sale | 25.00% |
EXPLORATION AND EVALUATION EX95
EXPLORATION AND EVALUATION EXPENDITURE (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
EXPLORATION AND EVALUATION EXPENDITURE | |||
Total exploration and evaluation expenditures | $ 42,726 | $ 34,366 | |
Less amount classified as asset held for sale | (61,064) | (18,309) | |
Total Exploration and Evaluation Expenditure, net of assets held for sale | 34,979 | 34,366 | $ 26,323 |
Exploration and evaluation phase, at cost | |||
EXPLORATION AND EVALUATION EXPENDITURE | |||
Total exploration and evaluation expenditures | 185,819 | 176,550 | |
Provision for impairment | |||
EXPLORATION AND EVALUATION EXPENDITURE | |||
Total exploration and evaluation expenditures | (143,093) | $ (142,184) | |
Exploration and evaluation assets | |||
EXPLORATION AND EVALUATION EXPENDITURE | |||
Less amount classified as asset held for sale | $ (7,747) |
EXPLORATION AND EVALUATION EX96
EXPLORATION AND EVALUATION EXPENDITURE - Movements in carrying amounts (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Exploration and evaluation | |||
Balance at the beginning of the period | $ 34,366 | $ 26,323 | |
Amounts capitalised during the period | 8,528 | 4,429 | |
Exploration costs expensed | 30 | $ 7,925 | |
Exploration costs expensed | (30) | (7,925) | |
Exploration tenements sold during the period | (2,096) | ||
Impairment expense (adjustment) | 5,583 | 10,203 | 321,918 |
Balance at end of period | 34,979 | 34,366 | $ 26,323 |
Exploration and evaluation assets | |||
Exploration and evaluation | |||
Impairment expense (adjustment) | (168) | (7,871) | |
Reclassifications from assets held for sale | $ 13,611 | ||
Reclassifications to assets held for sale | $ (7,747) | ||
Exploration and evaluation assets | Eagle Ford | |||
Exploration and evaluation | |||
Assets classified as held for sale (in percent) | 25.00% |
IMPAIRMENT OF ASSETS (Details)
IMPAIRMENT OF ASSETS (Details) $ in Thousands | May 01, 2017USD ($) | Jun. 30, 2015USD ($) | Dec. 31, 2017USD ($)$ / bbl | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($)$ / bbl |
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Impairment expense (adjustment) | $ 5,583 | $ 10,203 | $ 321,918 | ||
Loss on sale of non-current assets | $ 1,461 | $ (790) | |||
Producing properties pre-tax rate | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Discount rate | 9.00% | ||||
Undeveloped properties pre-tax rate | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Discount rate | 20.00% | ||||
Producing properties post-tax rate | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Discount rate | 9.00% | ||||
Discount rate | 9.00% | ||||
Undeveloped properties post-tax rate | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Discount rate | 20.00% | ||||
Discount rate | 10.00% | ||||
Undeveloped properties risk-adjustment rate | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Discount rate | 20.00% | ||||
Year 1 | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Future commodity price | $ / bbl | 60 | 40 | |||
1-2 Years | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Future commodity price | $ / bbl | 62.50 | 50 | |||
2-3 Years | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Future commodity price | $ / bbl | 65 | 60 | |||
3-4 Years | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Future commodity price | $ / bbl | 67.50 | ||||
4-5 Years | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Future commodity price | $ / bbl | 70 | ||||
Later than three years | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Future commodity price | $ / bbl | 70 | ||||
More than 5 years | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Future commodity price | $ / bbl | 75 | ||||
Dimmit County | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Fair value less costs to sell | $ 61,000 | ||||
Impairment expense | 5,400 | ||||
Recoverable amount | 61,000 | ||||
Mississippian/Woodward assets | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Impairment expense (adjustment) | 4,600 | ||||
Loss on sale of non-current assets | 1,300 | ||||
Mississippian/Woodford | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Loss on sale of non-current assets | $ 1,300 | ||||
Cooper Basin | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Fair value less costs to sell | 0 | ||||
Impairment expense (adjustment) | 200 | 6,700 | $ 2,200 | ||
Capital cost incurred and impaired | 200 | ||||
Recoverable amount | 0 | ||||
Cash generating unit | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Impairment expense (adjustment) | 10,200 | ||||
Cash generating unit | Gross impairment expense | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Impairment expense (adjustment) | 11,300 | ||||
Cash generating unit | Impairment adjustment | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Impairment expense (adjustment) | (1,100) | ||||
Exploration and evaluation expenditures | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Fair value less costs to sell | 39,935 | ||||
Impairment expense (adjustment) | 7,871 | (123,836) | |||
Carrying costs | 7,871 | 163,771 | |||
Recoverable amount | 39,935 | ||||
Exploration and evaluation expenditures | Dimmit County | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Fair value less costs to sell | 61,064 | ||||
Impairment expense (adjustment) | 5,415 | ||||
Carrying costs | 66,479 | ||||
Recoverable amount | 61,064 | ||||
Exploration and evaluation expenditures | Mississippian/Woodward assets | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Fair value less costs to sell | 1,190 | ||||
Impairment expense (adjustment) | $ 13,400 | (3,974) | |||
Carrying costs | 5,164 | ||||
Recoverable amount | 1,190 | ||||
Exploration and evaluation expenditures | Mississippian/Woodford | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Impairment expense (adjustment) | 1,183 | ||||
Carrying costs | 1,183 | ||||
Exploration and evaluation expenditures | Cooper Basin | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Fair value less costs to sell | 5,234 | ||||
Impairment expense (adjustment) | 6,688 | (2,202) | |||
Carrying costs | 6,688 | 7,436 | |||
Recoverable amount | 5,234 | ||||
Exploration and evaluation expenditures | Eagle Ford | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Fair value less costs to sell | 33,511 | ||||
Impairment expense (adjustment) | (117,660) | ||||
Carrying costs | 151,171 | ||||
Recoverable amount | 33,511 | ||||
Development and production assets | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Fair value less costs to sell | 18,309 | 327,942 | |||
Impairment loss | $ 0 | ||||
Impairment expense (adjustment) | 3,384 | (181,794) | |||
Carrying costs | 21,693 | 509,736 | |||
Recoverable amount | 18,309 | 327,942 | |||
Development and production assets | Mississippian/Woodward assets | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Impairment expense (adjustment) | $ 2,600 | ||||
Development and production assets | Mississippian/Woodford | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Fair value less costs to sell | 18,309 | 19,859 | |||
Impairment expense (adjustment) | 3,384 | (58,081) | |||
Carrying costs | 21,693 | 77,940 | |||
Recoverable amount | $ 18,309 | 19,859 | |||
Development and production assets | Eagle Ford | |||||
IMPAIRMENT OF NON-CURRENT ASSETS | |||||
Fair value less costs to sell | 308,083 | ||||
Impairment expense (adjustment) | (123,713) | ||||
Carrying costs | 431,796 | ||||
Recoverable amount | $ 308,083 |
PROPERTY AND EQUIPMENT (Details
PROPERTY AND EQUIPMENT (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 |
PROPERTY AND EQUIPMENT | |||
Property and equipment | $ 1,246 | $ 1,211 | $ 1,382 |
Exploration and evaluation phase, at cost | |||
PROPERTY AND EQUIPMENT | |||
Property and equipment | 3,628 | 3,146 | |
Accumulated depreciation | |||
PROPERTY AND EQUIPMENT | |||
Property and equipment | $ (2,382) | $ (1,935) |
PROPERTY AND EQUIPMENT - Moveme
PROPERTY AND EQUIPMENT - Movements in carrying amounts (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Movements in carrying amounts: | ||
Property, plant and equipment at beginning of period | $ 1,211 | $ 1,382 |
Amounts capitalized during the period | 659 | 355 |
Amounts disposed of during the period | (122) | (151) |
Depreciation expense | (502) | (375) |
Property, plant and equipment at end of period | $ 1,246 | $ 1,211 |
TRADE AND OTHER PAYABLES AND100
TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
TRADE AND OTHER PAYABLES AND ACCRUED EXPENSES | ||
Oil and natural gas property and operating related | $ 40,001 | $ 18,588 |
Administrative expenses, including salaries and wages | 4,494 | 2,225 |
Accrued interest payable | 3,057 | 2,761 |
Commodity derivative contract payables | 550 | |
Total trade, other payables and accrued expenses | $ 48,102 | $ 23,574 |
PRODUCTION PREPAYMENT (Details)
PRODUCTION PREPAYMENT (Details) $ in Thousands | Jan. 01, 2018$ / bbl | Jul. 31, 2017USD ($) | Apr. 30, 2018$ / bbl | Dec. 31, 2017USD ($)$ / bbl |
Production prepayment | $ | $ 30,000 | $ 18,194 | ||
Production prepayment, per annum interest rate | 10.00% | |||
Repayment, price per gross barrel | 25 | 20 | ||
Forecast | ||||
Repayment, price per gross barrel | 40 |
OTHER PROVISIONS (Details)
OTHER PROVISIONS (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)item | |
OTHER PROVISIONS | ||
Provisions, current | $ 1,158 | $ 2,726 |
Other provision | ||
OTHER PROVISIONS | ||
Balance at the beginning of the period | 6,025 | |
New provisions | 6,025 | |
Changes in estimates | (747) | |
Settlements | (1,932) | |
Unwinding of discount | 73 | |
Reclassification from provisions to accrued liabilities | (103) | |
Balance at end of period | $ 3,316 | $ 6,025 |
Third-party refracture | Schlumberger | ||
OTHER PROVISIONS | ||
Number of eagle ford wells to be refractured | item | 5 | |
Term of the agreement | 5 years |
CREDIT FACILITIES (Details)
CREDIT FACILITIES (Details) $ in Thousands | May 14, 2015USD ($)installment | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($) |
CREDIT FACILITIES | |||
Total Credit Facilities | $ 192,000 | $ 191,750 | |
Deferred financing fees, net of accumulated amortization | (2,690) | (3,501) | |
Total credit facilities, net of deferred financing fees | 189,310 | 188,249 | |
Borrowing base | $ 67,000 | ||
Number of monthly installment | installment | 5 | ||
Bottom of range | |||
CREDIT FACILITIES | |||
Current ratio | 1 | ||
Interest coverage ratio | 2 | ||
Asset coverage ratio, consisting of PV9% to Total Debt | 1.50 | ||
Top of range | |||
CREDIT FACILITIES | |||
Leverage ratio | 4 | ||
Revolving facility | |||
CREDIT FACILITIES | |||
Total Credit Facilities | 67,000 | 66,750 | |
Maximum borrowing capacity | $ 300,000 | ||
Term of credit facility | 5 years | ||
Revolving facility | LIBOR | Bottom of range | |||
CREDIT FACILITIES | |||
Adjustment to interest rate basis | 2.00% | ||
Revolving facility | LIBOR | Top of range | |||
CREDIT FACILITIES | |||
Adjustment to interest rate basis | 3.00% | ||
Term loan | |||
CREDIT FACILITIES | |||
Total Credit Facilities | $ 125,000 | $ 125,000 | $ 125,000 |
Term of credit facility | 5 years 6 months | ||
Term loan | LIBOR | Bottom of range | |||
CREDIT FACILITIES | |||
Interest rate | 8.00% | ||
Term loan | LIBOR | Top of range | |||
CREDIT FACILITIES | |||
Adjustment to interest rate basis | 7.00% |
RESTORATION PROVISION (Details)
RESTORATION PROVISION (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Restoration Provision Roll-forward | ||
Balance at the beginning of the period | $ 7,072 | |
Balance at end of period | 7,567 | $ 7,072 |
Restoration provision | ||
Restoration Provision Roll-forward | ||
Balance at the beginning of the period | 7,072 | 3,088 |
New provisions | 938 | 305 |
Changes in estimates | 663 | 2,956 |
Disposals and settlements | (256) | (114) |
New provisions assumed from acquisition | 894 | |
Unwinding of discount | 214 | 140 |
Reclassification from liabilities related to assets held for sale | 744 | |
Reclassification to liabilities related to assets held for sale | (1,064) | (941) |
Balance at end of period | $ 7,567 | $ 7,072 |
DEFERRED TAX ASSETS AND LIAB105
DEFERRED TAX ASSETS AND LIABILITIES (Details) - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
DEFERRED TAX ASSETS AND LIABILITIES | ||
Total net deferred tax assets | $ 1,995 | $ 2,683 |
Deferred tax liability (asset) | (1,995) | |
Share issuance costs | ||
DEFERRED TAX ASSETS AND LIABILITIES | ||
Total net deferred tax assets | 1,534 | |
Net operating loss carried forward | ||
DEFERRED TAX ASSETS AND LIABILITIES | ||
Total net deferred tax assets | 2,636 | |
Deferred tax liability (asset) | 23,976 | 7,218 |
Accrued interest | ||
DEFERRED TAX ASSETS AND LIABILITIES | ||
Total net deferred tax assets | (2,756) | |
Deferred tax liability (asset) | 3,436 | |
Derivatives | ||
DEFERRED TAX ASSETS AND LIABILITIES | ||
Total net deferred tax assets | 1,884 | |
Development and production expenditure | ||
DEFERRED TAX ASSETS AND LIABILITIES | ||
Total net deferred tax assets | 1,269 | |
Total net deferred tax liabilities | (25,971) | $ (10,654) |
Other | ||
DEFERRED TAX ASSETS AND LIABILITIES | ||
Total net deferred tax assets | $ 111 |
ISSUED CAPITAL (Details)
ISSUED CAPITAL (Details) $ / shares in Units, $ in Thousands | 4 Months Ended | 12 Months Ended | |||
Apr. 30, 2018USD ($)EquityInstrumentsshares | Dec. 31, 2017USD ($)EquityInstruments$ / sharesshares | Dec. 31, 2016USD ($)EquityInstrumentstranche$ / sharesshares | Dec. 31, 2015USD ($)EquityInstruments$ / sharesshares | Dec. 31, 2014EquityInstruments | |
Issued capital | |||||
Balance | $ | $ 372,764 | $ 373,585 | |||
Shares issued in conjunction with private placement | $ | $ 67,499 | $ 1,576 | |||
Cost of capital raising during the period, net of tax benefit | $ | (2,343) | ||||
Derecognition of deferred tax asset (see note 7) | $ | (821) | ||||
Closing balance at end of period | $ | 372,764 | 373,585 | |||
Proceeds from shares issued | $ | 67,499 | ||||
Tax benefit recognized on the cost of capital | $ | (200) | 1,000 | |||
Borrowings | $ | 192,000 | 191,750 | |||
Ordinary shares issued | |||||
Ordinary Shares | |||||
Number of additional ordinary shares issued | shares | 5,614,447,268 | ||||
Equity raise | $ | $ 260,000 | ||||
Equity raising costs | |||||
Issued capital | |||||
Tax benefit recognized on the cost of capital | $ | $ (821) | $ 986 | |||
Restricted stock units (RSUs) | |||||
Issued capital | |||||
RSUs outstanding | 33,803,361 | 23,782,201 | 12,434,338 | 2,964,177 | |
Measurement period | 3 years | ||||
Number of RSUs vested | 3,897,911 | 5,501,538 | 3,805,789 | ||
Forfeited | 1,838,145 | 1,417,791 | 46,312 | ||
Restricted stock units (RSUs) | Shares vested and forfeited | |||||
Issued capital | |||||
Measurement period | 3 years | ||||
Restricted stock units (RSUs) | 15 April 2014 | |||||
Issued capital | |||||
RSUs outstanding | 393,311 | ||||
Restricted stock units (RSUs) | 30 May 2014 | |||||
Issued capital | |||||
RSUs outstanding | 167,997 | ||||
Restricted stock units (RSUs) | 28 May 2015 | |||||
Issued capital | |||||
RSUs outstanding | 515,037 | 1,030,075 | |||
Restricted stock units (RSUs) | 28 May 2015 2nd tranche | |||||
Issued capital | |||||
RSUs outstanding | 1,545,113 | 1,545,113 | |||
Restricted stock units (RSUs) | 28 May 2015 2nd tranche | Shares vested and forfeited | |||||
Issued capital | |||||
Number of RSUs vested | 1,081,579 | ||||
Forfeited | 463,534 | ||||
Restricted stock units (RSUs) | 24 June 2015 | |||||
Issued capital | |||||
RSUs outstanding | 1,122,571 | 2,382,229 | |||
Restricted stock units (RSUs) | 24 June 2015 2nd tranche | |||||
Issued capital | |||||
RSUs outstanding | 2,267,879 | 2,267,879 | |||
Restricted stock units (RSUs) | 24 June 2015 2nd tranche | Shares vested and forfeited | |||||
Issued capital | |||||
Number of RSUs vested | 1,587,516 | ||||
Forfeited | 680,363 | ||||
Restricted stock units (RSUs) | 1 August 2015 | |||||
Issued capital | |||||
RSUs outstanding | 107,000 | 214,000 | |||
Restricted stock units (RSUs) | 15 March 2016 | |||||
Issued capital | |||||
RSUs outstanding | 6,824,951 | 6,824,950 | |||
Restricted stock units (RSUs) | 27 May 2016 | |||||
Issued capital | |||||
RSUs outstanding | 4,342,331 | 4,342,331 | |||
Restricted stock units (RSUs) | 29 June 2016 | |||||
Issued capital | |||||
RSUs outstanding | 1,633,763 | 3,614,316 | |||
Restricted stock units (RSUs) | 15 August 2016 | |||||
Issued capital | |||||
RSUs outstanding | 800,000 | ||||
Restricted stock units (RSUs) | 15 August 2016 2nd tranche | |||||
Issued capital | |||||
RSUs outstanding | 200,000 | ||||
Restricted stock units (RSUs) | 3 January 2017 | |||||
Issued capital | |||||
RSUs outstanding | 187,500 | ||||
Restricted stock units (RSUs) | 17 February 2017 (2) | |||||
Issued capital | |||||
RSUs outstanding | 6,627,667 | ||||
Restricted stock units (RSUs) | 25 May 2017 (2) | |||||
Issued capital | |||||
RSUs outstanding | 3,724,191 | ||||
Restricted stock units (RSUs) | 23 October 2017 (2) | |||||
Issued capital | |||||
RSUs outstanding | 745,000 | ||||
Restricted stock units (RSUs) | 23 October 2017 2nd tranche | |||||
Issued capital | |||||
RSUs outstanding | 1,500,000 | ||||
Restricted stock units (RSUs) | 29 December 2017 | |||||
Issued capital | |||||
RSUs outstanding | 2,660,358 | ||||
Ordinary shares | |||||
Ordinary Shares | |||||
Par value per share | $ / shares | $ 0 | $ 0 | $ 0 | ||
Total shares issued and outstanding | shares | 1,253,249,528 | 1,249,351,617 | 559,103,562 | ||
Shares issued during the year | shares | 3,897,911 | 690,248,055 | |||
Total shares issued and outstanding | shares | 1,253,249,528 | 1,249,351,617 | 559,103,562 | ||
Shares held in escrow | shares | 1,500,000 | 1,500,000 | 1,500,000 | ||
Issued capital | |||||
Private placement, number of tranches | tranche | 3 | ||||
Number of shares issued | shares | 685,000,000 | ||||
Net proceeds from shares issued | $ | $ 64,200 | ||||
Issued capital | |||||
Issued capital | |||||
Balance | $ | $ 372,764 | $ 373,585 | 308,429 | ||
Shares issued in conjunction with private placement | $ | 67,499 | $ 1,576 | |||
Total shares issued during the period | $ | 67,499 | ||||
Cost of capital raising during the period, net of tax benefit | $ | (2,343) | ||||
Derecognition of deferred tax asset (see note 7) | $ | (821) | ||||
Closing balance at end of period | $ | $ 372,764 | $ 373,585 | $ 308,429 |
CAPITAL AND OTHER EXPENDITUR107
CAPITAL AND OTHER EXPENDITURE COMMITMENTS (Details) $ in Thousands, $ in Millions | 12 Months Ended | |||
Dec. 31, 2017AUD ($) | Dec. 31, 2017USD ($) | Dec. 31, 2016USD ($)item | Dec. 31, 2017USD ($) | |
Other Commitments [Line Items] | ||||
Expenditure commitments | $ 9,321 | $ 6,306 | ||
Operating lease commitments | 2,400 | |||
Number of wells | item | 7 | |||
Bottom of range | ||||
Other Commitments [Line Items] | ||||
Mineral lease term | 3 years | 3 years | ||
Top of range | ||||
Other Commitments [Line Items] | ||||
Mineral lease term | 5 years | 5 years | ||
Cooper Basin capital commitments | ||||
Other Commitments [Line Items] | ||||
Capital commitments incurred | $ 6.2 | $ 4,800 | $ 5,900 | |
Capital commitments | 3,373 | 3,490 | ||
Cooper Basin capital commitments | Top of range | ||||
Other Commitments [Line Items] | ||||
Capital commitments | $ 10.6 | |||
Drilling rig commitments | ||||
Other Commitments [Line Items] | ||||
Expenditure commitments | $ 1,085 | |||
Number of drilling rigs | item | 1 | |||
Operating lease commitments | ||||
Other Commitments [Line Items] | ||||
Operating lease commitments | $ 4,123 | 2,446 | ||
Employment commitments | ||||
Other Commitments [Line Items] | ||||
Expenditure commitments | 740 | 370 | ||
Year 1 | ||||
Other Commitments [Line Items] | ||||
Expenditure commitments | 4,495 | 3,165 | ||
Year 1 | Cooper Basin capital commitments | ||||
Other Commitments [Line Items] | ||||
Capital commitments | 1,687 | 1,745 | ||
Year 1 | Drilling rig commitments | ||||
Other Commitments [Line Items] | ||||
Expenditure commitments | 1,085 | |||
Year 1 | Operating lease commitments | ||||
Other Commitments [Line Items] | ||||
Operating lease commitments | 1,353 | 1,050 | ||
Year 1 | Employment commitments | ||||
Other Commitments [Line Items] | ||||
Expenditure commitments | 370 | 370 | ||
1 - 5 years | ||||
Other Commitments [Line Items] | ||||
Expenditure commitments | 503 | |||
1 - 5 years | Operating lease commitments | ||||
Other Commitments [Line Items] | ||||
Operating lease commitments | 503 | |||
More than 5 years | ||||
Other Commitments [Line Items] | ||||
Expenditure commitments | 4,323 | 3,141 | ||
More than 5 years | Cooper Basin capital commitments | ||||
Other Commitments [Line Items] | ||||
Capital commitments | 1,686 | 1,745 | ||
More than 5 years | Operating lease commitments | ||||
Other Commitments [Line Items] | ||||
Operating lease commitments | 2,267 | $ 1,396 | ||
More than 5 years | Employment commitments | ||||
Other Commitments [Line Items] | ||||
Expenditure commitments | $ 370 |
OPERATING SEGMENTS (Details)
OPERATING SEGMENTS (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($)segment | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
Disclosure of impairment loss and reversal of impairment loss [line items] | |||
Number of reportable segments | segment | 1 | ||
Pre-tax impairment expense | $ 5,583 | $ 10,203 | $ 321,918 |
Cooper Basin | |||
Disclosure of impairment loss and reversal of impairment loss [line items] | |||
Pre-tax impairment expense | $ 200 | $ 6,700 | $ 2,200 |
OPERATING SEGMENTS - Geographic
OPERATING SEGMENTS - Geographic Information (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($)customeritem | Dec. 31, 2016USD ($)customer | Dec. 31, 2015customer | |
Disclosure of major customers [line items] | |||
Number of geographic locations | item | 2 | ||
Assets | $ 454,618 | $ 432,088 | |
Number of major customers | customer | 2 | 2 | 3 |
Australia | |||
Disclosure of major customers [line items] | |||
Assets | $ 0 | $ 0 | |
Major customer one | |||
Disclosure of major customers [line items] | |||
Percentage of entity's revenue | 50.00% | 69.00% | 30.00% |
Major customer two | |||
Disclosure of major customers [line items] | |||
Percentage of entity's revenue | 34.00% | 12.00% | 29.00% |
Major customer three | |||
Disclosure of major customers [line items] | |||
Percentage of entity's revenue | 22.00% |
CASH FLOW INFORMATION (Details)
CASH FLOW INFORMATION (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
Loss from ordinary activities after income tax | $ (22,435) | $ (45,694) | $ (263,835) |
Adjustments to reconcile net profit to net operating cash flows: | |||
Depreciation and amortisation expense | 58,361 | 48,147 | 94,584 |
Share based compensation | 2,076 | 2,524 | 4,100 |
Unrealised losses on derivatives | 1,224 | 21,433 | (3,444) |
Net loss on sale of non-current assets | (1,461) | 790 | |
Decrease in fair value of securities at fair value through the profit and loss | 90 | ||
Impairment of development and production assets | 5,583 | 10,203 | 321,918 |
Unsuccessful exploration and evaluation expense | 30 | ||
Loss on debt extinguishment | 1,151 | ||
Add: Interest expense and financing costs (disclosed in investing and financing activities) | 12,676 | 12,219 | 9,418 |
Recognition (derecognition) of deferred tax assets on items directly within equity | (821) | 986 | |
Recognition (derecognition) of deferred tax assets on items directly within equity | (200) | 1,000 | |
Less: Gain from escrow settlement, insurance proceeds and litigation settlements (disclosed in investing activities) | (2,200) | (3,603) | |
Less: Loss on foreign currency derivative (disclosed in financing activities) | 390 | ||
Other | 541 | 21 | 2,240 |
Changes in assets and liabilities | |||
Decrease (increase) in current and deferred income tax | 2,888 | (826) | (100,583) |
Decrease (increase) in other current assets | 72 | (511) | 2,742 |
Decrease in trade and other receivables | 5,241 | 2,009 | 7,007 |
Increase (decrease) in trade and other payables | 9,633 | (5,080) | (2,177) |
Decrease in tax receivable | 476 | 412 | (6,522) |
Decrease in non-current liability | (1,430) | ||
NET CASH PROVIDED BY OPERATING ACTIVITIES | 74,776 | 42,660 | $ 64,469 |
Equity raising costs | |||
Adjustments to reconcile net profit to net operating cash flows: | |||
Recognition (derecognition) of deferred tax assets on items directly within equity | $ (821) | $ 986 |
CASH FLOW INFORMATION - Non cas
CASH FLOW INFORMATION - Non cash activity (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
CASH FLOW INFORMATION | |||
Non-cash additions to oil and gas properties | $ 27,726 | $ 13,161 | $ 22,559 |
SHARE BASED PAYMENTS (Details)
SHARE BASED PAYMENTS (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
SHARE BASED PAYMENTS | |||
Share based compensation expense | $ 1,868 | $ 2,748 | $ 4,100 |
SHARE BASED PAYMENTS - Restrict
SHARE BASED PAYMENTS - Restricted Stock Units (Details) | 6 Months Ended | 12 Months Ended | ||||||
Aug. 31, 2016EquityInstruments | Sep. 30, 2015EquityInstruments | Dec. 31, 2017$ / shares | Dec. 31, 2017USD ($)EquityInstruments | Dec. 31, 2016$ / shares | Dec. 31, 2016USD ($)EquityInstruments | Dec. 31, 2015$ / shares | Dec. 31, 2015USD ($)EquityInstruments | |
Disclosure of terms and conditions of share-based payment arrangement [line items] | ||||||||
Share based compensation expense | $ | $ 1,868,000 | $ 2,748,000 | $ 4,100,000 | |||||
Restricted stock units (RSUs) | ||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | ||||||||
Share based compensation expense | $ | $ 2,100,000 | $ 2,500,000 | $ 4,100,000 | |||||
Outstanding RSUs at beginning of period | 23,782,201 | 12,434,338 | 2,964,177 | |||||
Issued or Issuable | 16,992,192 | 13,332,262 | 15,757,216 | 18,267,192 | 13,322,262 | |||
Converted to ordinary shares | (3,897,911) | (5,501,538) | (3,805,789) | |||||
Forfeited | (1,838,145) | (1,417,791) | (46,312) | |||||
Outstanding RSUs at end of period | 33,803,361 | 23,782,201 | 12,434,338 | |||||
Weighted average fair value at measurement date, RSUs, beginning of period | $ | $ 0.34 | $ 0.55 | $ 0.93 | |||||
Weighted average fair value at measurement date, RSUs, issued or issuable | $ / shares | $ 0.09 | $ 0.18 | $ 0.53 | |||||
Weighted average fair value at measurement date, RSUs, converted | $ | 0.43 | 0.54 | 0.63 | |||||
Weighted average fair value at measurement date, RSUs, forfeited | $ | 0.15 | 0.59 | 0.93 | |||||
Weighted average fair value at measurement date, RSUs, end of period | $ | $ 0.22 | $ 0.34 | $ 0.55 | |||||
ASX | RSUs issued from option conversion | ||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | ||||||||
Issued or Issuable | 1,275,000 | |||||||
Employees | Restricted stock units (RSUs) | ||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | ||||||||
Issued or Issuable | 15,757,216 | 16,992,192 | 13,322,262 | |||||
Managing Director | Restricted stock units (RSUs) | ||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | ||||||||
Issued or Issuable | 3,724,191 | 5,113,281 | 3,090,000 |
SHARE BASED PAYMENTS - RSUs Awa
SHARE BASED PAYMENTS - RSUs Awarded (Details) | Dec. 29, 2017EquityInstruments$ / shares | Oct. 23, 2017EquityInstruments$ / shares | May 25, 2017EquityInstruments$ / shares | Feb. 02, 2017EquityInstruments$ / shares | Jan. 09, 2017EquityInstruments$ / shares | Jan. 03, 2017EquityInstruments$ / shares | Aug. 15, 2016EquityInstruments$ / shares | Jun. 29, 2016EquityInstruments$ / shares | May 27, 2016EquityInstruments$ / shares | May 17, 2016 | Mar. 15, 2016EquityInstruments$ / shares | Sep. 01, 2015EquityInstruments$ / shares | Jun. 24, 2015EquityInstruments$ / shares | May 28, 2015EquityInstruments$ / shares | Apr. 27, 2015EquityInstruments$ / shares | Aug. 31, 2016EquityInstruments | Sep. 30, 2015EquityInstruments | Dec. 31, 2017USD ($)$ / shares | Dec. 31, 2017USD ($)EquityInstruments$ / shares | Dec. 31, 2016USD ($)$ / shares | Dec. 31, 2016USD ($)EquityInstruments | Dec. 31, 2015$ / shares | Dec. 31, 2015USD ($)EquityInstruments |
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Vesting period | 3 years | ||||||||||||||||||||||
Share based compensation expense | $ | $ 1,868,000 | $ 2,748,000 | $ 4,100,000 | ||||||||||||||||||||
Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Number of RSUs | EquityInstruments | 16,992,192 | 13,332,262 | 15,757,216 | 18,267,192 | 13,322,262 | ||||||||||||||||||
Fair value at measurement date (Per RSU) | $ 0.09 | $ 0.18 | $ 0.53 | ||||||||||||||||||||
Measurement period | 3 years | ||||||||||||||||||||||
Weighted average exercise price RSU (per share) | $ 0.19 | $ 0.11 | $ 0.52 | ||||||||||||||||||||
Weighted average remaining contractual life | 1 year 4 months 24 days | ||||||||||||||||||||||
Share based compensation expense | $ | $ 2,100,000 | $ 2,500,000 | $ 4,100,000 | ||||||||||||||||||||
Deferred Cash Awards | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Deferred cash awards | $ | $ 2,302,645 | 2,302,645 | $ 2,048,198 | 2,048,198 | |||||||||||||||||||
Share-based compensation (income) | $ | $ (200,000) | ||||||||||||||||||||||
Share based compensation expense | $ | $ 200,000 | ||||||||||||||||||||||
Estimated deferred cash award, per unit | $ 0.03 | ||||||||||||||||||||||
Liabilities from share-based payment transactions | $ | $ 16,000 | $ 16,000 | |||||||||||||||||||||
Vesting based on ATSR | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Number of RSUs | EquityInstruments | 745,000 | 3,724,191 | 6,627,667 | 800,000 | 4,342,331 | 6,824,950 | |||||||||||||||||
Fair value at measurement date (Per RSU) | $ 0.03 | $ 0.05 | $ 0.12 | $ 0.11 | $ 0.10 | $ 0.15 | |||||||||||||||||
Measurement period | 3 years | 3 years | 3 years | 3 years | 3 years | 3 years | |||||||||||||||||
Vesting on issuance date | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Number of RSUs | EquityInstruments | 770,950 | 2,809,479 | |||||||||||||||||||||
Fair value at measurement date (Per RSU) | $ 0.12 | $ 0.40 | |||||||||||||||||||||
Vesting percentage | 100.00% | 100.00% | |||||||||||||||||||||
Vesting on anniversary dates | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Number of RSUs | EquityInstruments | 2,660,358 | 250,000 | 250,000 | 3,853,961 | 321,000 | 4,267,002 | 1,545,113 | 28,874 | |||||||||||||||
Fair value at measurement date (Per RSU) | $ 0.07 | $ 0.24 | $ 0.22 | $ 0.08 | $ 0.25 | $ 0.40 | $ 0.45 | $ 0.52 | |||||||||||||||
Vesting percentage | 33.00% | 25.00% | 25.00% | 25.00% | 33.00% | 33.00% | 33.00% | 33.00% | 25.00% | ||||||||||||||
Vesting on specific date | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Number of RSUs | EquityInstruments | 1,500,000 | 400,000 | |||||||||||||||||||||
Fair value at measurement date (Per RSU) | $ 0.05 | $ 0.11 | |||||||||||||||||||||
Vesting period | 90 days | ||||||||||||||||||||||
Vesting percentage | 25.00% | 25.00% | 25.00% | 50.00% | |||||||||||||||||||
Vesting on next specific date | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Vesting percentage | 50.00% | ||||||||||||||||||||||
Vesting based on total shareholder return | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Number of RSUs | EquityInstruments | 2,815,681 | 1,545,113 | |||||||||||||||||||||
Fair value at measurement date (Per RSU) | $ 0.57 | $ 0.67 | |||||||||||||||||||||
Measurement period | 3 years | 3 years | |||||||||||||||||||||
Employees | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Number of RSUs | EquityInstruments | 15,757,216 | 16,992,192 | 13,322,262 | ||||||||||||||||||||
Bottom of range | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Measurement period | 1 year | ||||||||||||||||||||||
Bottom of range | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Vesting percentage | 0.00% | ||||||||||||||||||||||
Bottom of range | Deferred Cash Awards | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Measurement period | 1 year | ||||||||||||||||||||||
Vesting percentage | 0.00% | ||||||||||||||||||||||
Bottom of range | Vesting based on ATSR | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Vesting percentage | 0.00% | 0.00% | 0.00% | 0.00% | 0.00% | ||||||||||||||||||
Bottom of range | Vesting based on total shareholder return | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Vesting percentage | 0.00% | 0.00% | |||||||||||||||||||||
Top of range | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Measurement period | 3 years | ||||||||||||||||||||||
Vesting percentage | 300.00% | ||||||||||||||||||||||
Top of range | Deferred Cash Awards | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Measurement period | 3 years | ||||||||||||||||||||||
Top of range | Vesting based on ATSR | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Vesting percentage | 150.00% | ||||||||||||||||||||||
Top of range | Vesting based on ATSR | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Vesting percentage | 150.00% | 150.00% | 133.00% | 133.00% | 133.00% | ||||||||||||||||||
Top of range | Vesting on specific date | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Vesting period | 90 days | 90 days | |||||||||||||||||||||
Top of range | Vesting based on total shareholder return | Restricted stock units (RSUs) | |||||||||||||||||||||||
Disclosure of terms and conditions of share-based payment arrangement [line items] | |||||||||||||||||||||||
Vesting percentage | 200.00% | 200.00% |
SHARE BASED PAYMENTS - Deferred
SHARE BASED PAYMENTS - Deferred Cash Awards (Details) - Deferred Cash Awards - USD ($) | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Disclosure of terms and conditions of share-based payment arrangement [line items] | ||
Deferred cash awards, Beginning balance | $ 2,048,198 | |
Granted | 1,998,675 | $ 2,079,879 |
Forfeited | (1,744,228) | (31,681) |
Deferred cash awards, Ending balance | $ 2,302,645 | $ 2,048,198 |
FINANCIAL RISK MANAGEMENT - Com
FINANCIAL RISK MANAGEMENT - Commodity Price Risk Exposure and Management (Details) - 12 months ended Dec. 31, 2017 | Total | $ / Mcf | $ / bbl | bbl | Mcf | Total |
Oil Derivatives | ||||||
Commodity Price Risk Exposure and Management | ||||||
Outstanding derivative positions | bbl | 1,827,000 | |||||
Weighted Average Floor Price | $ / bbl | 50.28 | |||||
Weighted Average Ceiling Price | $ / bbl | 55.07 | |||||
Gas Derivatives | ||||||
Commodity Price Risk Exposure and Management | ||||||
Outstanding derivative positions | Mcf | 3,534,000 | |||||
Weighted Average Floor Price | $ / Mcf | 2.85 | |||||
Weighted Average Ceiling Price | $ / Mcf | 3.30 | |||||
Year 1 | Oil Derivatives | ||||||
Commodity Price Risk Exposure and Management | ||||||
Outstanding derivative positions | bbl | 891,000 | |||||
Weighted Average Floor Price | $ / bbl | 50.40 | |||||
Weighted Average Ceiling Price | $ / bbl | 56.86 | |||||
Year 1 | Gas Derivatives | ||||||
Commodity Price Risk Exposure and Management | ||||||
Outstanding derivative positions | Mcf | 2,106,000 | |||||
Weighted Average Floor Price | $ / Mcf | 2.92 | |||||
Weighted Average Ceiling Price | $ / Mcf | 3.24 | |||||
1-2 Years | Oil Derivatives | ||||||
Commodity Price Risk Exposure and Management | ||||||
Outstanding derivative positions | bbl | 828,000 | |||||
Weighted Average Floor Price | $ / bbl | 50.56 | |||||
Weighted Average Ceiling Price | $ / bbl | 53.49 | |||||
1-2 Years | Gas Derivatives | ||||||
Commodity Price Risk Exposure and Management | ||||||
Outstanding derivative positions | Mcf | 1,212,000 | |||||
Weighted Average Floor Price | $ / Mcf | 2.78 | |||||
Weighted Average Ceiling Price | $ / Mcf | 3.47 | |||||
2-3 Years | Oil Derivatives | ||||||
Commodity Price Risk Exposure and Management | ||||||
Outstanding derivative positions | bbl | 108,000 | |||||
Weighted Average Floor Price | $ / bbl | 47.05 | |||||
Weighted Average Ceiling Price | $ / bbl | 52.50 | |||||
2-3 Years | Gas Derivatives | ||||||
Commodity Price Risk Exposure and Management | ||||||
Outstanding derivative positions | Mcf | 216,000 | |||||
Weighted Average Floor Price | $ / Mcf | 2.54 | |||||
Weighted Average Ceiling Price | $ / Mcf | 2.93 | |||||
Commodity price risk | ||||||
Commodity Price Risk Exposure and Management | ||||||
Percentage of proved developed reserves to hedge | 50.00% | |||||
Rolling period (in months) | 36 months | |||||
Commodity price risk | Swaps | ||||||
Commodity Price Risk Exposure and Management | ||||||
Outstanding derivative positions | 1,089,000 | 1,350,000 |
FINANCIAL RISK MANAGEMENT - Cre
FINANCIAL RISK MANAGEMENT - Credit Risk (Details) - Credit Risk $ in Millions | Dec. 31, 2017USD ($)item |
Credit Risk | |
Number of customers owing more than 10% of accrued revenue receivables | item | 3 |
Customer one | |
Credit Risk | |
Percentage of accrued revenue receivables accounted | 39.00% |
Trade receivables | $ 1 |
Customer two | |
Credit Risk | |
Percentage of accrued revenue receivables accounted | 29.00% |
Trade receivables | $ 0.8 |
Customer three | |
Credit Risk | |
Percentage of accrued revenue receivables accounted | 22.00% |
Trade receivables | $ 0.6 |
FINANCIAL RISK MANAGEMENT - Liq
FINANCIAL RISK MANAGEMENT - Liquidity Risk (Details) - Liquidity Risk - USD ($) $ in Thousands | Dec. 31, 2017 | Dec. 31, 2016 |
Liquidity Risk | ||
Financial liabilities | $ 295,545 | $ 265,040 |
Trade and other payable | ||
Liquidity Risk | ||
Financial liabilities | 9,051 | 3,579 |
Accrued expenses | ||
Liquidity Risk | ||
Financial liabilities | 39,051 | 19,995 |
Production prepayment | ||
Liquidity Risk | ||
Financial liabilities | 18,194 | |
Provisions | ||
Liquidity Risk | ||
Financial liabilities | 3,316 | 6,025 |
Credit facilities payments, including interest | ||
Liquidity Risk | ||
Financial liabilities | 225,933 | 235,441 |
Year 1 | ||
Liquidity Risk | ||
Financial liabilities | 81,128 | 38,906 |
Year 1 | Trade and other payable | ||
Liquidity Risk | ||
Financial liabilities | 9,051 | 3,579 |
Year 1 | Accrued expenses | ||
Liquidity Risk | ||
Financial liabilities | 39,051 | 19,995 |
Year 1 | Production prepayment | ||
Liquidity Risk | ||
Financial liabilities | 18,194 | |
Year 1 | Provisions | ||
Liquidity Risk | ||
Financial liabilities | 1,158 | 2,726 |
Year 1 | Credit facilities payments, including interest | ||
Liquidity Risk | ||
Financial liabilities | 13,674 | 12,606 |
1 - 5 years | ||
Liquidity Risk | ||
Financial liabilities | 214,417 | 226,134 |
1 - 5 years | Provisions | ||
Liquidity Risk | ||
Financial liabilities | 2,158 | 3,299 |
1 - 5 years | Credit facilities payments, including interest | ||
Liquidity Risk | ||
Financial liabilities | $ 212,259 | $ 222,835 |
FINANCIAL RISK MANAGEMENT - 119
FINANCIAL RISK MANAGEMENT - Commodity Price Risk (Details) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017USD ($)item$ / Mcf$ / bbl | Dec. 31, 2016USD ($) | |
FINANCIAL RISK MANAGEMENT | ||
Number of types of market risk | item | 3 | |
Commodity price risk | ||
FINANCIAL RISK MANAGEMENT | ||
Sensitivity analysis assumptions movement in crude oil prices | $ / bbl | 10 | |
Sensitivity analysis assumptions movement in natural gas prices | $ / Mcf | 0.50 | |
Commodity price appreciation risk | ||
FINANCIAL RISK MANAGEMENT | ||
Sensitivity analysis assumptions movement in crude oil prices | $ / bbl | 10 | |
Sensitivity analysis assumptions movement in natural gas prices | $ / Mcf | 0.50 | |
Oil - Effect on profit before tax | $ (14,287) | $ (12,813) |
Gas - Effect on profit before tax | $ (1,254) | (1,423) |
Commodity price depreciation risk | ||
FINANCIAL RISK MANAGEMENT | ||
Sensitivity analysis assumptions movement in crude oil prices | $ / bbl | 10 | |
Sensitivity analysis assumptions movement in natural gas prices | $ / Mcf | 0.50 | |
Oil - Effect on profit before tax | $ 15,961 | 16,233 |
Gas - Effect on profit before tax | $ 1,504 | $ 1,306 |
FINANCIAL RISK MANAGEMENT - Int
FINANCIAL RISK MANAGEMENT - Interest Rate Risk (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2017 | Dec. 31, 2016 | |
Interest rate appreciation risk | ||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||
Effect on profit before tax Increase / (Decrease) | $ (3,663) | $ (3,357) |
Increase in interest rate (as a percent) | 2.00% | |
Interest rate depreciation risk | ||
Disclosure of nature and extent of risks arising from financial instruments [line items] | ||
Effect on profit before tax Increase / (Decrease) | $ 1,177 | $ 396 |
Decrease in interest rate (as a percent) | 2.00% |
SUBSIDIARIES (Details)
SUBSIDIARIES (Details) | 12 Months Ended |
Dec. 31, 2017 | |
Sundance Energy Inc. | |
Disclosure of subsidiaries [line items] | |
Percentage owned | 100.00% |
Sundance Energy Oklahoma, LLC | |
Disclosure of subsidiaries [line items] | |
Percentage owned | 100.00% |
SEA Eagle Ford, LLC | |
Disclosure of subsidiaries [line items] | |
Percentage owned | 100.00% |
Armadillo Eagle Ford Holdings, Inc. | |
Disclosure of subsidiaries [line items] | |
Percentage owned | 100.00% |
Armadillo E&P, Inc. | |
Disclosure of subsidiaries [line items] | |
Percentage owned | 100.00% |
NSE PEL570 LTD | |
Disclosure of subsidiaries [line items] | |
Percentage owned | 100.00% |
EVENTS AFTER THE BALANCE SHE122
EVENTS AFTER THE BALANCE SHEET DATE (Details) $ in Thousands | Apr. 23, 2018USD ($)ashares | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | Dec. 31, 2017USD ($) | Jul. 31, 2017USD ($) | May 14, 2015USD ($) |
Disclosure of non-adjusting events after reporting period [line items] | ||||||
Issue of equity | $ 67,499 | $ 1,576 | ||||
Borrowings | $ 191,750 | $ 192,000 | ||||
Borrowing capacity | $ 67,000 | |||||
Production prepayment | $ 18,194 | $ 30,000 | ||||
Deferred financing | $ 4,708 | |||||
Acquisition agreement | Eagle Ford | ||||||
Disclosure of non-adjusting events after reporting period [line items] | ||||||
Net acres | a | 21,900 | |||||
Cash consideration | $ 221,500 | |||||
Ordinary shares issued | Eagle Ford | ||||||
Disclosure of non-adjusting events after reporting period [line items] | ||||||
Issue of equity | $ 260,000 | |||||
Ordinary shares issued | Eagle Ford | Ordinary shares | ||||||
Disclosure of non-adjusting events after reporting period [line items] | ||||||
Number of shares issued | shares | 5,614,447,268 | |||||
Refinanced debt facilities | ||||||
Disclosure of non-adjusting events after reporting period [line items] | ||||||
Repayment of borrowings | $ 192,000 | |||||
Refinanced debt facilities | Eagle Ford | ||||||
Disclosure of non-adjusting events after reporting period [line items] | ||||||
Production prepayment | 11,800 | |||||
Refinanced debt facilities | Eagle Ford | Second lien term loan | ||||||
Disclosure of non-adjusting events after reporting period [line items] | ||||||
Borrowings | 250,000 | |||||
Refinanced debt facilities | Eagle Ford | Syndicated revolving facility | ||||||
Disclosure of non-adjusting events after reporting period [line items] | ||||||
Borrowing capacity | 87,500 | |||||
Maximum borrowing capacity | $ 250,000 |
UNAUDITED SUPPLEMENTAL OIL A123
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES - Costs Incurred (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($)item | Dec. 31, 2016USD ($) | Dec. 31, 2015USD ($) | |
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Property acquisition costs proved | $ 4,335 | $ 23,873 | $ 13,170 |
Property acquisition costs unproved | 1,244 | 2,815 | 15,495 |
Exploration costs | 2,949 | 1,650 | 10,353 |
Development costs | 115,120 | 61,131 | 76,831 |
Capitalised costs incurred | $ 123,648 | 89,469 | 115,849 |
Development costs associated with non-producing wells in progress | $ 5,000 | $ 16,600 | |
Number of wells in progress | item | 0 |
UNAUDITED SUPPLEMENTAL OIL A124
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES - SEC Oil and Gas Reserve Information (Details) | 12 Months Ended | ||
Dec. 31, 2017MBoeMMcfMBbls | Dec. 31, 2016MBoeMMcfMBbls | Dec. 31, 2015MBoeMMcfMBbls | |
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Proved Developed and Undeveloped Reserves, Net, Beginning Balance (MBoe) | MBoe | 29,490 | 25,473 | 25,981 |
Revisions of previous estimates (MBoe) | MBoe | (1,972) | (2,141) | (6,068) |
Extensions and discoveries (MBoe) | MBoe | 12,386 | 7,500 | 3,336 |
Purchases of reserves in-place (MBoe) | MBoe | 11,278 | 3,168 | 4,876 |
Production (MBoe) | MBoe | (2,727) | (2,234) | (2,652) |
Sales of reserves in-place (MBoe) | MBoe | (1,376) | (2,276) | |
Proved Developed and Undeveloped Reserves, Net, Ending Balance (MBoe) | MBoe | 47,079 | 29,490 | 25,473 |
Proved developed reserves (MBoe): | MBoe | 15,744 | 12,493 | 10,578 |
Proved undeveloped reserves (MBoe) | MBoe | 31,335 | 16,997 | 14,895 |
Ryder Scott Company, L.P. | Mr. Gardner | |||
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Practical experience in petroleum engineering studies | 12 years | ||
Oil | |||
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Proved Developed and Undeveloped Reserves, Net, Beginning Balance | 18,441 | 17,552 | 17,026 |
Revisions of previous estimates | (1,778) | (1,397) | (3,491) |
Extensions and discoveries | 6,658 | 4,242 | 1,950 |
Purchases of reserves in-place | 6,892 | 1,432 | 3,896 |
Production | (1,800) | (1,412) | (1,829) |
Sales of reserves in-place | (426) | (1,976) | |
Proved Developed and Undeveloped Reserves, Net, Ending Balance | 27,987 | 18,441 | 17,552 |
Proved developed reserves: | 8,987 | 7,440 | 6,379 |
Proved undeveloped reserves | 19,000 | 11,001 | 11,173 |
Natural gas | |||
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Proved Developed and Undeveloped Reserves, Net, Beginning Balance | MMcf | 35,730 | 26,576 | 28,733 |
Revisions of previous estimates | MMcf | (2,091) | 536 | (8,152) |
Extensions and discoveries | MMcf | 17,255 | 10,240 | 4,122 |
Purchases of reserves in-place | MMcf | 14,935 | 3,121 | 4,454 |
Production | MMcf | (3,621) | (2,941) | (2,581) |
Sales of reserves in-place | MMcf | (2,799) | (1,802) | |
Proved Developed and Undeveloped Reserves, Net, Ending Balance | MMcf | 59,409 | 35,730 | 26,576 |
Proved developed reserves: | MMcf | 21,078 | 16,704 | 13,205 |
Proved undeveloped reserves | MMcf | 38,331 | 19,026 | 13,371 |
NGL | |||
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Proved Developed and Undeveloped Reserves, Net, Beginning Balance | 5,094 | 3,492 | 4,166 |
Revisions of previous estimates | 154 | (833) | (1,218) |
Extensions and discoveries | 2,852 | 1,551 | 699 |
Purchases of reserves in-place | 1,897 | 1,216 | 238 |
Production | (324) | (332) | (393) |
Sales of reserves in-place | (483) | ||
Proved Developed and Undeveloped Reserves, Net, Ending Balance | 9,190 | 5,094 | 3,492 |
Proved developed reserves: | 3,244 | 2,269 | 1,998 |
Proved undeveloped reserves | 5,946 | 2,825 | 1,494 |
UNAUDITED SUPPLEMENTAL OIL A125
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES - SEC Oil and Gas Reserve Information other (Details) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2017USD ($)MBoe | Dec. 31, 2016USD ($)MBoe | Dec. 31, 2015USD ($)MBoe | |
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Proved undeveloped reserves (MBoe) | 31,335 | 16,997 | 14,895 |
Increase in proved undeveloped reserves | 14,338 | ||
Decrease in proved reserves | 1,972 | 2,141 | 6,068 |
Extensions and discoveries (MBoe) | 12,386 | 7,500 | 3,336 |
Revisions of previous estimates | 2,534 | ||
Conversion to proved developed reserves | 3,948 | ||
Duration over which future development costs expects to fund with operating cash flows | 5 years | ||
Future development costs associated with proved undeveloped reserves | $ | $ 508,500 | ||
Net cash flow | $ | $ 647,309 | $ 310,285 | $ 379,909 |
Expected duration within which reserves will be spud | 5 years | ||
Revisions of previous estimates (MBoe) | (1,972) | (2,141) | (6,068) |
Eagle Ford | |||
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Decrease in proved reserves | 1,972 | 2,141 | |
Extensions and discoveries (MBoe) | 12,386 | 7,500 | 3,303 |
Purchases of reserves in-place | 10,678 | ||
Revisions of previous estimates (MBoe) | (1,972) | (2,141) | |
Revisions of previous estimates (as a percent) | 100.00% | ||
Extensions and discoveries (as a percent) | 100.00% | 99.00% | |
Mississippian/Woodford formation | |||
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Decrease in proved reserves | 5,900 | ||
Revisions of previous estimates (MBoe) | (5,900) | ||
Revisions of previous estimates (as a percent) | 97.00% | ||
Undeveloped reserves | Eagle Ford | |||
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Extensions and discoveries | 10,140 |
UNAUDITED SUPPLEMENTAL OIL A126
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES - Standardized Measure of Future Net Cash Flow (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | Dec. 31, 2017 | Dec. 31, 2016 | Dec. 31, 2015 | |
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | ||||||
Cash inflows | $ 1,866,923 | $ 892,576 | $ 936,041 | |||
Production costs | (667,438) | (307,907) | (246,277) | |||
Development costs | (516,243) | (274,384) | (308,253) | |||
Income tax expense | (35,933) | (1,602) | ||||
Net cash flow | 647,309 | 310,285 | 379,909 | |||
10% annual discount rate | (280,562) | (151,146) | (198,142) | |||
Standardized measure of discounted future net cash flows | $ 159,139 | $ 181,767 | $ 435,506 | $ 366,747 | $ 159,139 | $ 181,767 |
Standardized Measure, beginning of period | 159,139 | 181,767 | 435,506 | |||
Sales, net of production costs | (75,370) | (49,496) | (67,693) | |||
Net change in sales prices, net of production costs | 7,899 | (62,670) | (369,770) | |||
Extensions and discoveries, net of future production and development costs | 94,151 | 3,603 | 11,609 | |||
Changes in future development costs | 17,128 | 5,331 | 28,092 | |||
Previously estimated development costs incurred during the period | 51,414 | 45,012 | 31,007 | |||
Revision of quantity estimates | (20,598) | 9,762 | (91,440) | |||
Accretion of discount | 15,914 | 18,217 | 53,173 | |||
Change in income taxes | (14,492) | 402 | 95,827 | |||
Purchases of reserves in-place | 88,280 | 17,004 | 442 | |||
Sales of reserves in-place | (7,544) | 845 | ||||
Change in production rates and other | 50,826 | (10,638) | 55,014 | |||
Standardized Measure, end of period | $ 366,747 | $ 159,139 | $ 181,767 |
UNAUDITED SUPPLEMENTAL OIL A127
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES - Impact of Pricing (Details) | 12 Months Ended | ||
Dec. 31, 2017$ / Mcf$ / bbl | Dec. 31, 2016$ / Mcf$ / bbl | Dec. 31, 2015$ / Mcf$ / bbl | |
Oil | |||
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Average prices | 52.60 | 42.02 | 48.47 |
Natural gas | |||
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Average prices | $ / Mcf | 3.17 | 1.22 | 1.27 |
NGL | |||
UNAUDITED SUPPLEMENTAL OIL AND GAS DISCLOSURES | |||
Average prices | 22.47 | 14.55 | 14.80 |