UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 6-K

 

Report of Foreign Private Issuer
 Pursuant to Rule 13a-16 or 15d-16 under the Securities Exchange Act of 1934

 

For the month of September 2018

 

Commission File Number 000-55246

 

Sundance Energy Australia Limited

(Translation of registrant’s name into English)

 

633 17th Street, Suite 1950
Denver, CO  80202

(Address of principal executive office)

 

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F.

 

Form 20-F ☒           Form 40-F ☐

 

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(1): ☐

 

Indicate by check mark if the registrant is submitting the Form 6-K in paper as permitted by Regulation S-T Rule 101(b)(7): ☐

 

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934.

 

Yes ☐                      No ☒

If “Yes” is marked, indicate below the file number assigned to the registrant in connection with Rule 12g3-2(b):  n/a

 

 

 

 

sdfsd

 

Exhibit 99.1 is incorporated by reference in the Registration Statements on Form S-8 (Registration Number 333-204490) and Form F-3 (Registration Number 333-216220 and 333-224583) of Sundance Energy Australia Limited.

 

 

SIGNATURES

 

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

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

INTERIM FINANCIAL REPORT

 

HALF-YEAR ENDED 

30 JUNE 2018

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ABN 76 112 202 883

 

 

 

 

Table of Contents

 

 

 

DIRECTORS’ REPORT

Your Directors submit the financial report of Sundance Energy Australia Limited (the “Company” or “the consolidated group”) for the half‐year ended 30 June 2018.

 

Directors

The names of each person who has been a Director during the half‐year and to the date of this report are: 

Michael D. Hannell – Non‐Executive Chairman

Eric P. McCrady – Managing Director and CEO 

Damien A. Hannes – Non‐Executive Director 

Neville W. Martin – Non–Executive Director 

Weldon Holcombe – Non‐Executive Director

 

Company Secretary

Damien Connor has been the Company Secretary during the half‐year and to the date of this report.

 

Corporate Updates

 

On 23 April 2018, the Company acquired from Pioneer Natural Resources USA, Inc., Reliance Industries and Newpek, LLC approximately 21,900 net acres in the Eagle Ford in McMullen, Live Oak, Atascosa and La Salle counties, Texas, for a cash purchase price of $215.8 million, after effective date to closing date adjustments estimated at $5.8 million.  The acquisition included working interests in 132 gross (98.0 net) wells producing approximately 1,700 Boe/d.  The acquisition furthered the Company’s strategy of aggregating assets in the Eagle Ford and increased the Company’s drilling inventory. 

 

The Company funded the acquisition with a portion of the proceeds from its $260.0 million capital raise in March and April 2018 (including the impact of derivative instruments).  Contemporaneous with the closing of its Eagle Ford acquisition, the Company entered into a  $250.0 million syndicated second lien term loan with Morgan Stanley Energy Capital, as administrative agent, (the “Term Loan”), and a syndicated revolver with Natixis, New York Branch, as administrative agent, (the “Revolving Facility”), with a $250.0 million face and initial availability of $87.5 million.  The proceeds of the refinanced debt facilities were used to retire the Company’s previous credit facilities of $192.0 million, repay the remaining outstanding production prepayment of $11.8 million and pay deferred financing fees of $16.7 million, with the balance available for the Company’s working capital needs. 

 

Review of Operations

 

Revenues and Production.  The following table provides the components of our revenues for the six months ended 30 June 2018 and 2017, as well as each period’s respective sales volumes:

 

 

 

Barrel of oil equivalent (Boe) and average net daily production (Boe/d). Sales volume increased by 97,571 Boe (8.1%) to 1,298,239 Boe (7,173 Boe/d) for the six months ended 30 June 2018 compared to 1,200,668 Boe  (6,634 Boe/d) for the same period in prior year primarily due to production from the Company’s newly acquired Eagle Ford wells (116,107 Boe or 641 Boe/d) beginning 23 April 2018, partially offset by no longer having production from Oklahoma properties disposed of in the first half of 2017 (77,952 Boe or 431 Boe/d).  In addition, the Company had initial production from 3 gross (3.0 net wells) in June 2018.  As at 30 June 2018, the Company was in the process of drilling 4 gross (4.0 net) wells and had 5 gross (5.0 net) wells waiting on completion.  As of the date of this report, the 9 gross (9.0 net) wells in progress at 30 June 2018 have had initial production. 

 

Our sales volume is oil‐weighted, with oil representing 57% and 64% of total sales volume for the six‐months ended 30 June 2018 and 2017, respectively.  Oil production as a percentage of sales during the first half of 2018 was temporarily reduced due to certain oilier wells being shut-in for installation of artificial lift and to facilitate the completion of offset wells. 

 

Oil sales. Oil sales increased by $5.5 million (14.6%) to $43.0 million for the six‐months ended 30 June 2018  from $37.5 million for the same period in prior year. The increase in oil revenues was the result of higher product pricing ($6.8 million), partially offset by lower production volumes ($1.3 million). Oil production volumes decreased 26,607 Bbls (3.4%) to 745,774 Bbls for the six months ended 30 June 2018 compared to 772,381 Bbls for the same period in prior year. The average realised price on the sale of oil increased by 18.7% to $57.64 per Bbl for the six months ended 30 June 2018 from $48.56 per Bbl for the same period in prior year.  The average realized price per Bbl was negatively impacted by a fixed delivery contract which ended in June 2018 (approximately $8.97 per Bbl).  Exclusive of the fixed delivery contract, the realized price on the sale of oil would have been $66.61 per Bbl for the six months ended 30 June 2018. 

 

Natural gas sales. Natural gas sales increased by $1.1 million (25.7%) to $5.2 million for the six months ended 30 June 2018 from $4.2 million for the same period in prior year. The increase in natural gas revenues was the result of increased production volumes ($1.2 million), partially offset by lower product pricing ($0.1 million). Natural gas production volumes increased 464,681 Mcf (28.0%) to 2,126,647 Mcf for the six months ended 30 June 2018 compared to 1,661,993 Mcf for the same period in prior year. The average realised price on the sale of natural gas decreased by 2.0% to $2.45 per Mcf for the six months ended 30 June 2018 from $2.50 per Mcf for the same period in prior year.

 

NGL sales. NGL sales increased by $1.8 million (62.8%) to $4.6 million for the six months ended 30 June 2018 from $2.8 million for the same period in prior year. The increase in NGL revenues was the result of increased production volumes ($0.9 million) as well as higher product pricing ($0.9 million). NGL production volumes increased 46,731 Bbls (30.9%) to 198,019 Bbls for the six months ended 30 June 2018 compared to 151,288 Bbls for the same period in prior year. The average realised price on the sale of NGL increased by 24.4  % to $23.04 per Bbl for the six months ended 30 June 2018 from $18.52 per Bbl for the same period in prior year.

 

 

 

Lease operating expenses (“LOE”). LOE increased by $6.1 million (81.4%) to $13.7 million for the six‐months ended 30 June 2018 from $7.5 million for the same period in prior year and increased $4.26 per Boe (67.9%) to $10.53 per Boe from $6.27 per Boe. The increase in LOE was partially due to higher gathering costs under the midstream agreements associated with the Company’s acquired properties.  Under the IFRS revenue recognition standards (adopted by the Company in 2018), these costs are classified as LOE. 

 

Workover expense. Workover expenses decreased by $0.4 million (13.3%) to $2.5 million for the six months ended 30 June 2018 from $2.9 million for the same period in prior year. Workover expense in 2018 was primarily related to procedures performed to increase recovery from certain on Company’s legacy assets and on the recently acquired wells. 

 

Production taxes. Production taxes increased by $0.9 million (31.2%) to $3.7 million for the six months ended 30 June 2018 due to higher revenue, but increased as a percentage of revenue (7.1%  compared to 6.4% in the prior period.) The increase in the percentage of revenue was primarily due the change in production mix (oil is taxed at a lower statutory severance tax rate than natural gas) and a minor increase in ad valorem tax.

 

Depreciation, depletion and amortisation expense (“DD&A”). DD&A decreased by $1.2 million (4.2%) to $27.2 million for the six months ended 30 June 2018 from $28.4 million for the same period in prior year. DD&A was lower in 2018 primarily due to the Company’s Dimmit County assets being classified as held for sale and therefore no DD&A was recorded related to these assets during the six months ended 30 June 2018, but were recorded in the same comparable period in 2017. 

 

General and administrative expenses (“G&A”). G&A expenses increased by $11.0 million (122.4%) to $20.1 million for the six months ended 30 June 2018 from $9.0 million for the same period in prior year. G&A for the six months ended 30 June 2018 included transaction-related costs related to the Company’s Eagle Ford acquisition totaling $12.4 million, or $9.53 per Boe.  G&A, excluding transaction costs, decreased as compared to the same period in prior year due to lower professional fees ($1.8 million) offset by higher employee salaries and salary-related expenses ($0.9 million). 

 

Finance costs. Finance costs, net of amounts capitalised to exploration and development, increased by $4.8 million (80.3%) to $10.8 million for the six‐months ended 30 June 2018 as compared to $6.0 million in the same period in prior year. The increase in finance costs during the six months ended 30 June 2018 was primarily driven by an increase in the amount of average outstanding debt during the period as well as a higher effective interest rate on the Term Loan.  In addition, the Company had a revenue advance outstanding from its then oil purchaser with a balance of $18.2 million as of 1 January 2018.  The revenue advance was repaid through delivery of the Company’s oil production, and was repaid in full in April 2018 upon completion of the Company’ s refinance.  The Company incurred $0.4 million of interest expense related to the revenue advance during the six months ended 30 June 2018.  Finance costs during the six months ended 30 June 2018 also included an unrealized loss on the Company’s interest rate swap of $0.4 million. 

 

The weighted average interest rate on the Company’s outstanding debt at 30 June 2018 was 10.34% compared to 6.75% at the comparable prior year date.    

 

Loss on debt extinguishment. The Company recognized a loss of $2.4 million during the six months ended 30 June 2018 related to the write-off of deferred financing costs on its previous credit facilities. 

 

(Loss) gain on commodity derivative financial instruments. The Company recognized a net loss on derivative financial instruments during the six months ended 30 June 2018 consisting of $19.3 million of unrealised losses on commodity derivative contracts and $3.9 million of realised losses on commodity derivative contracts. The unrealised loss represents the change in the fair value of the Company’s net derivative position primarily due to the increase in commodity prices since 31 December 2017.

 

Gain on foreign currency derivative financial instruments. The Company realised a gain of $6.8 million during the six months ended 30 June 2018 related to derivative contracts put into place to protect the capital commitments made by investors as part of the Company’s equity raise from changes in the AUD to USD exchange rate during the period from launch of equity raise to receipt of funds.  

 

Income tax expense.  The Company recognized income tax expense of $7.6 million during the six months ended 30 June 2018 primarily due to an Internal Revenue Code (“IRC”) §382 limitation on the ability to use existing U.S. net operating losses to offset future U.S. taxable income.  The IRC §382 limitation was triggered due to a greater than 50% ownership change resulting from the capital raise in 2018. 

Adjusted EBITDAX. The Company uses both IFRS and certain non‐IFRS measures to assess its performance. Management believes Adjusted EBITDAX is useful because it allows it to more effectively evaluate the Company’s operating performance, identify operating trends and compare the results of operations from period to period without regard to financing policies and capital structure. Management excludes the items listed below from profit attributable to owners of Sundance in arriving at Adjusted EBITDAX, because these amounts can vary substantially from company to company within our industry, depending upon accounting policies and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDAX should not be considered as an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with IFRS, as issued by the IASB, or as an indicator of the Company’s operating performance or liquidity.

Adjusted EBITDAX is defined as earnings before interest expense, income taxes, depreciation, depletion and amortisation, property impairments, gain/(loss) on sale of non‐current assets, exploration expense, share‐based compensation, restructuring charges, gains and losses on commodity hedging, net of settlements of commodity hedging and certain other non‐cash or non‐recurring income/expense items. For the six‐months ended 30 June 2018, adjusted EBITDAX was $21.5 million compared to $22.5 million from the same period in prior year.

 

The following table presents a reconciliation of the loss attributable to owners of Sundance to Adjusted EBITDAX:

 

(1) Other items of expense, net for the period ended 30 June 2017 included $1.0 million expense related legal settlement with the buyer from a sale of the Company’s North Dakota properties in 2013, $0.6 million related to a deposit for which collectability was uncertain and $0.1 million of restructuring related costs. 

 

Development

 

The Company’s development activities during the first half of 2018 totaled $44.3 million, primarily related to drilling costs for 12 gross (12.0 net) operated wells, and completion costs for 3 gross (3.0 net) wells.  Each of the wells completed during the period had initial production in June 2018.  As at 30 June 2018, the Company was in the process of drilling 4 gross (4.0 net) wells, with 5 gross (5.0 net) Sundance-operated wells waiting on completion.  As of the date of this report, the 9 gross (9.0 net) wells in progress at 30 June 2018 have had initial production.  

 

The 3.0 net wells with initial production in June 2018 and 2.0 net wells waiting on completion at 30 June 2018 were located on the Company’s legacy acreage.  The remaining wells are located on the newly acquired acreage. 

 

Exploration

 

During the six months ended 30 June 2018, the Company’s exploration expenditures totaled $6.4 million, primarily for seismic data for the newly acquired Eagle Ford assets.

 

Financial Position and Liquidity

 

As at 30 June 2018, the Company had $6.3 million of cash and equivalents.  The Company had $250 million outstanding on its Term Loan and $12.0 million of letters of credit outstanding on its Revolving Facility, leaving available borrowing capacity of $75.5 million under the Revolving Facility.  Subsequent to 30 June 2018, the Company drew down $20 million on the Revolving Facility. The Company’s credit facility covenants include maintaining a minimum Current Ratio of 1.0, a maximum Revolver Debt to EBITDA ratio of 4.0, a minimum interest coverage ratio of 2.0 and a minimum asset coverage ratio (PV9 of proved reserves to total debt) of at least 1.5. The Company was in compliance with its  covenants as at 30 June 2018.

 

Following is a summary of the Company’s open oil and natural gas derivative contracts at 30 June 2018:

 

 

Subsequent to 30 June 2018, the Company contracted an additional 180,000 Bbls, 860,000 Bbls and 540,000 Bbls for 2018, 2019 and 2020, respectively.  The contracted prices range from $55.00 to $68.23 per  Bbl.  In addition, the Company entered into propane derivative contracts covering 68,000 Bbls, 312,000 Bbls and 271,000 Bbls for 2018, 2019 and 2020, respectively.  The contracted prices range from $0.70 to $0.89 per Bbl.   

 

Commitments

 

In conjunction with the Eagle Ford acquisition, the Company entered into new midstream contracts covering the gathering, processing, transport and marketing of production for the newly acquired properties.  The contracts contain commitments to deliver oil, natural gas and NGL volumes to meet minimum revenue commitments (“MRC”) of $81.7 million through 2022, a portion of which are secured by letters of credit and performance bonds.  Under the terms of the contract, if the Company fails to deliver the volumes to satisfy the MRC, it is required to pay a deficiency payment equal to the shortfall.  If the volumes and associated fees are in excess of the MRC in any year, the overage can be applied to reduce the commitment in the subsequent years.  Due to the timing of the acquisition, the Company’s 2018 development program is back-loaded in 2018.  As a result, the Company anticipates it may have a shortfall under the agreements of up to $2.7 million for 2018. The amount of the shortfall, if any, that may exist at 31 December 2018 will be highly dependent on the timing of well completions and the production results from new drilling. 

 

Auditor’s Declaration

 

The auditor’s independence declaration as required under section 307C of the Corporations Act 2001 is set out on page 6 for the half‐year ended 30 June 2018 financial report.

 

Signed in accordance with a resolution of the Board of Directors.

 

Mike Hannell

Chairman

Adelaide

Dated this 13th day of September 2018

 

The Board of Directors

Sundance Energy Australia Limited

Ground Floor

28 Greenhill Road

Wayville, South Australia, 5034

 

13 September 2018

 

 

Dear Board Members,

Sundance Energy Australia Limited

 

 

In accordance with section 307C of the Corporations Act 2001, I am pleased to provide the following declaration of independence to the directors of Sundance Energy Australia Limited.

 

As lead audit partner for the review of the financial statements of Sundance Energy Australia Limited for the half-year ended 30 June 2018, I declare that to the best of my knowledge and belief, there have been no contraventions of:

 

 

Yours sincerely,

DELOITTE TOUCHE TOHMATSU

Jason Thorne

Partner

Chartered Accountant

 

 

Liability limited by a scheme approved under Professional Standards Legislation

Member of Deloitte Touche Tohmatsu Limited

CONDENSED CONSOLIDATED STATEMENTS OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

 

The accompanying notes are an integral part of these consolidated financial statements

CONDENSED CONSOLIDATED STATEMENTS OF FINANCIAL POSITION (UNAUDITED)

 

The accompanying notes are an integral part of these consolidated financial statements

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (UNAUDITED)

 

The accompanying notes are an integral part of these consolidated financial statements

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

 

The accompanying notes are an integral part of these consolidated financial statements

NOTE 1 — BASIS OF PREPARATION

 

The unaudited general purpose financial statements of Sundance Energy Australia Limited (“SEAL”) and its wholly owned subsidiaries, (collectively, the “Company”, “Consolidated Group” or “Group”), for the interim half‐year reporting period ended 30 June 2018 have been prepared in accordance with the Corporations Act 2001 and Australian Accounting Standards Board (“AASB”) 134 Interim Financial Reporting. These condensed consolidated financial statements comply with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”).

 

The interim condensed consolidated financial statements do not include all the information and disclosures required in the annual financial statements, and should be read in conjunction with the Company’s annual financial statements as at 31 December 2017 and any public announcements made by the Company during the interim reporting period in accordance with the continuous disclosure requirements of the Corporations Act 2001.

 

The accounting policies and methods of computation that are discussed in Note 1 of the Company’s 31 December 2017 annual financial statements have been consistently applied to the half‐year reporting period ended 30 June 2018 unless otherwise stated. On 1 January  2018, the Company adopted AASB/IFRS 15 – Revenue from Contracts with Customers.  The objective of the new standard is to establish a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers.  The standard was 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 Company elected the modified retrospective approach.  The adoption did not have an impact on the Company’s net income or cash flows, and the Company did not record a cumulative-effect adjustment to retained earnings as a result.    Refer to Note 3 for further information on the Company’s implementation of this standard.

 

On 1 January 2018 the Company adopted AASB 9/IFRS 9, Financial Instruments, and the relevant amending standards.  The standard introduces new requirements for the classification, measurement, and derecognition of financial instruments, including new general hedge accounting requirements.  The adoption of the standard did not have a material impact on the Group’s consolidated financial statements.

 

The condensed consolidated financial statements and accompanying notes are presented in U.S. dollars and all values are rounded to the nearest thousand (US$’000), except where stated otherwise.

 

NOTE 2 — ACQUISITIONS

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 in McMullen, Live Oak, Atascosa and La Salle counties, Texas for a cash purchase price of $215.8 million, after the effective date to closing date adjustments of $5.8 million; $4.4 million of which is expected to be received in the second half of 2018.  The acquisition included varying working interests in 132 gross  (98.0 net) wells. The acquisition furthers the Company’s strategy of aggregating assets in the Eagle Ford.  The acquisition was funded with a portion of the proceeds from its capital raise in March and April 2018. 

 

The following table reflects the provisional fair value of the assets acquired and the liabilities assumed as at the date of acquisition (in thousands):

 

The purchase price allocation for the Eagle Ford acquisition is provisional and is subject to further adjustments and certain post-closing adjustments with the seller.

 

Revenues of $5.3 million and net income, excluding general and administrative costs (which could not be practically estimated) and the impact of income taxes, of $1.9 million were generated from the acquired properties from 23 April 2018 through 30 June 2018. The Company incurred transaction costs totaling $13.7 million, of which $1.3 million was incurred in the second half of 2017.  These costs are included in general and administrative expenses on the condensed consolidated statement of loss.  The transaction costs included legal, accounting, valuation and other fees incurred to complete the acquisition. 

 

If the acquisition had been completed as of 1 January 2018, the Company’s pro forma revenue and loss before income taxes for the six months ended 30 June 2018 would have been $64.6 million and $(61.2) 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.

 

NOTE 3 – REVENUE

Adoption of IFRS 15

 

The Company adopted IFRS 15 effective 1 January 2018.  The standard was adopted using the modified retrospective approach which requires the Company to recognize in retained earnings at the date of adoption the cumulative effect of the application of IFRS 15 to all existing revenue contracts which were not substantially complete as of 1 January 2018.  The Company has elected the contract modification practical expedient which allows the Company to reflect the aggregate effect of all modifications prior to the date of adoption when applying the standard.  The implementation of the standard did not have an impact on the Company’s opening retained earnings, net income or cash flows.

 

Revenue from Contracts with Customers

 

The Company recognizes revenue from the sale of oil, natural gas and natural gas liquids (“NGL”s) in the period that the performance obligations are satisfied.  The Company’s performance obligations are primarily comprised of the delivery of oil, natural gas, or NGLs at a delivery point.  Each barrel of oil, MMBtu of natural gas, or other unit of measure is separately identifiable and represents a distinct performance obligation to which the transaction price is allocated.  Performance obligations are satisfied at a point in time once control of the product has been transferred to the customer through monthly delivery of oil, natural gas and NGLs.  Under certain of the Company’s marketing arrangements, the Company maintains control of the product during gathering, processing, and transportation, and these costs are recorded as lease operating expenses on the condensed consolidated statement of profit and loss.  Such fees that are incurred after control of the product has transferred are recorded as a reduction to the transaction price.

   

The Company’s contracts with customers typically require payment for oil, natural gas and NGL sales within one to two months following the calendar month of delivery.  The sales of oil, natural gas and NGLs typically include variable consideration that is based on pricing tied to local indices adjusted for fees and differentials and the quantity of volumes delivered. At the end of each month when the performance obligation is satisfied, the variable consideration can be reasonably estimated based on published commodity price indexes and metered production volumes, and amounts due from customers are accrued in trade and other receivables on the condensed consolidated balance sheets.  At 30 June 2018, the Company’s receivables from contracts with customers totaled $3.9 million.  Variances between the Company’s estimated revenue and actual payments are recorded in the month of payment.  These variances have not historically been material.

 

Disaggregation of Revenue

 

Below the Company has presented disaggregated revenue by product type.

 

 

Of the revenue recognized during the six months ended 30 June 2018, $1.7 million was not deemed to be revenue from contracts with customers. 

 

NOTE 4 — LEASE OPERATING EXPENSES

 

 

NOTE 5 — GENERAL AND ADMINISTRATIVE EXPENSES

 

 

NOTE 6 — IMPAIRMENT OF ASSETS

 

Non-current oil and gas assets

 

At 30 June 2018, the Group reassessed the carrying amount of 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 30 June 2018, the Company determined there was no indication of impairment or impairment reversal for its Eagle Ford oil and gas assets. 

 

Dimmit County Assets Held For Sale

 

In accordance with IFRS 5, assets held for sale are to be measured at the lower of fair value less cost to sell (“FVLCS”) or the carrying value of the assets. To estimate FVLCS of the Dimmit County disposal group at 30 June 2018, the Group utilized both the income approach (Level 3 on fair value hierarchy) based on the estimated discounted future cash flows from the producing property and related undeveloped properties, and the market approach, which took into account market multiples derived from comparable market transactions of similar assets and information from a third-party broker (Level 2 on fair value hierarchy).  The Company calculated a weighted average of the approaches based upon management’s assessed likelihood of the outcomes.  

 

The income approach model took into account current forward prices of oil and natural gas and various discount rates and risk adjustment factors.  The post-tax discount rates that have been applied to the Dimmit County disposal group were 9.0%, 20.0% and 25.0% for proved developed producing, proved undeveloped, and probable undeveloped properties, respectively. The Company applied further risk adjustment factors of 40% and 60% for proved and probable undeveloped properties, respectively.  The Company’s estimate used published futures pricing.

 

Both models included an estimate of costs that would be paid to the external broker marketing the assets. 

 

The Company estimated that the FVLCS as at 30 June 2018 was $41 million, which resulted in an impairment expense of $21.2 million.  Depletion is not recorded for the disposal group when classified for sale.  Any further adverse changes in any of the key assumptions may result in future impairments or a loss on sale at the time of disposition if and when the disposal group is sold. 

 

Cooper Basin

 

The Company recorded impairment expense of $0.7 million during the six months ended 30 June 2018 for additional costs incurred by the operator and billed to the Company (net to its interest) at the Cooper Basin during the period.  The Company continues to carry the asset value at nil value.  Impairment totaled $29 thousand during the six months ended 30 June 2017.

 

NOTE 7 — OTHER EXPENSE, NET

 

NOTE 8 – INCOME TAX EXPENSE

 

During the six months ended 30 June 2018 the Company recognized income tax expense of $7.6 million on a pre-tax loss of $66.0 million, representing (12)% of pre-tax loss.  Tax expense consists of $2.6 million in current tax expense and $5.0 million of deferred tax expense.  Tax expense differs from the prima facie tax expense at the Group’s statutory income tax rate of 30% due primarily to: $16.7 million de-recognition of deferred tax assets due to the IRC §382 change of ownership; $2.5 million of unrecognized tax benefit from current period losses; $5.8 million of tax expense related to US tax rates; and $2.3 million of withholding tax on U.S. source interest income.

 

As a result of the IRC §382 change of ownership, the Company’s use of pre-change losses will be limited to approximately $38.8 million.  Accordingly, the Company derecognized $16.7 million of existing deferred tax assets and reported a net deferred tax liability of $5.0 million at 30 June 2018.     

 

NOTE 9 — EARNINGS (LOSS) PER SHARE (“EPS”)

 

 

NOTE 10 — ASSETS HELD FOR SALE

The condensed consolidated statement of financial position includes assets and liabilities held for sale, comprised of the following:

 

In June 2017, the Company committed to a plan to sell its assets located in Dimmit County, Texas.  It shifted its marketing strategy in the second quarter of 2018 from an internal process to utilizing a third-party broker.  The assets to be sold include developed and production assets and exploration and evaluation expenditures.  Sale of the Dimmit assets