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| Share Name | Share Symbol | Market | Type | Share ISIN | Share Description |
|---|---|---|---|---|---|
| Ophir Energy Plc | LSE:OPHR | London | Ordinary Share | GB00B24CT194 | ORD 0.25P |
| Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
|---|---|---|---|---|---|---|---|---|---|---|
| 0.00 | 0.00% | 57.50 | 57.40 | 57.50 | 0.00 | 01:00:00 |
| Industry Sector | Turnover | Profit | EPS - Basic | PE Ratio | Market Cap |
|---|---|---|---|---|---|
| 0 | 0 | N/A | 0 |
From Apr 2019 to Apr 2024
TIDMOPHR
RNS Number : 6179A
Ophir Energy Plc
13 September 2018
13(th) September 2018
Ophir Energy plc
Half Year Results
Ophir Energy plc today reports results for the six months ended 30 June 2018.
Alan Booth, Interim CEO of Ophir, commented:
"As per the separate strategic update, the Board is rebalancing the company's portfolio towards a larger Asian production and cash flow base with the aim of building a stable, self-financing E&P company. The recent acquisition of assets from Santos is a considerable step towards this goal, doubling our production and operating cash flow.
"On Fortuna, we are continuing to work to deliver value for our shareholders whilst we are in possession of the licence. Reflecting the uncertainty surrounding this however, we have impaired the value of the asset to $300 million."
Highlights for 1H'18
-- Production average of 11,400 boepd, marginally ahead of expectations
-- Agreed acquisition of Southeast Asian package of assets from Santos for $205 million (as at effective date of 1 January 2018); the transaction closed in September with a net cash payment of $144 million (after adjusting for the value of cash flow from 1 January 2018)
-- Revenue of $102 million and net funds flow from production of $43 million
-- Impairments and write-offs of $358 million, mainly comprised of $310 million relating to Fortuna
-- Closing net cash of $75 million and closing liquidity of $371 million
2018 Outlook
-- Production from the Santos assets has been higher than predicted during the year which has reduced the expected payback of the transaction to 30 months
Hot Features
Premium
-- The table below summarises the outlook on a pro-forma and accounting basis:
Units Proforma IFRS Basis(**)
Basis(*)
FY 2018 FY 2018
-------------- ---------- --------------
Production (Mboepd) 27.5 17.0
-------------- ---------- --------------
Net funds flow from production ($'millions) 210 130
-------------- ---------- --------------
Acquisition cost (with effective
date of 1 January 2018) ($'millions) 205 144
-------------- ---------- --------------
Capital expenditure ($'millions) 145 125
-------------- ---------- --------------
Net debt ($'millions) 110 110
-------------- ---------- --------------
Gross liquidity (cash and undrawn
debt facility) ($'millions) 260 260
-------------- ---------- --------------
*Guidance on a 2018 full year pro forma basis assuming accounting for the Santos acquisition from the effective date of 1 January 2018.
**The 2018 full year financial results will reflect acquisition accounting from the completion date of 6 September 2018.
A presentation for investors and analysts will be held at 9.30am this morning. A webcast of the event will be available on the company's website: www.ophir-energy.com/investors and a dial in is available using the following number: +44 (0)330 336 9411.
For further enquiries, please contact:
Ophir Energy plc + 44 (0) 20 7811 2400
Geoff Callow, Head of IR and Corporate Communications
Brunswick (PR Adviser to Ophir) + 44 (0) 20 7404 5959
Patrick Handley
Wendel Verbeek
About Ophir:
Ophir Energy is an independent Upstream oil and gas exploration and production company. It is listed on the London Stock Exchange (LEI: 213800LAZOZTKPAV258).
Operational Review
Group Production
Group production in 1H 2018 was above expectations averaging 11,400 boepd, in part thanks to the Bualuang field outperforming against budgeted production. The next phase of development drilling on Bualuang, which was scheduled to commence in July, was delayed until August as the rig arrived 6 weeks later than schedule. The drilling is now well underway and production has increased to reflect this with full year production expected to be in line with budget.
August marked the tenth anniversary of the start of production from the Bualuang field. When the field commenced production 2P reserves were estimated at 15 MMbbls and it was expected to be onstream for only 5 years. In the past ten years, the field has produced over 33 MMbbls and is expected to produce nearly 60 MMbbls in total. Phase 4 of the field development is proceeding well and the 4D seismic is helping to define areas of the field with unswept reservoirs that will be targets for future development drilling.
The Kerendan field has continued to produce in line with expectations. Interpretation is well underway on the 3D seismic that was completed at the end of 2017, and has helped to define better the reservoir distribution and indicates that the contingent resources in the field could be materially in excess of the 457 Bcf (gross) that we carry today. We expect to have more confidence by year-end 2018 on the recoverable volumes and the potential to open up new routes to commercialisation.
Sinphuhorm continues to see erratic gas offtake nominations. The first quarter saw nominations under budget and the second quarter saw nominations over budget. As guided previously, we expect to see volatility in these numbers for the rest of the year.
Assets acquired from Santos
On 6 September 2018, we closed the acquisition for the Santos package of producing assets, of which the principal assets are the Chim Sao/Dua oil field in Vietnam and the Madura Offshore and Sampang PSCs in Indonesia. We have received the economic benefit of the 1H 2018 production from these assets which resulted in the net cash payment to Santos being $144 million in September 2018. All of the ex-Santos fields performed ahead of expectations and as a result will generate more operating cash flow than envisaged at the time of the acquisition.
Premier Oil, the operator of the Block 12W licence in Vietnam, which contains the Chim Sao and Dua fields, recently reported that the field maintained high levels of production in 1H 2018, with daily gross production averaging 29,000 boepd (9,200 boepd net to Ophir*). Two well intervention programmes are planned for 3Q 2018 to offset natural decline from the existing wells. One of these was completed in August with the other to follow. A combination of low operating costs, at $10 per boe, and an oil that commands a premium to the Brent oil price, underpins Block 12W as highly cash generative asset.
The Madura Offshore and Sampang PSCs combined to average 9,300 boepd (net to Ophir) during 1H 2018. The fields are late stage assets but through relatively modest incremental investment, there is an opportunity to tie in satellite fields and deeper reservoirs, which will both bring new barrels on stream and extend the life of the existing production.
An example of the upside opportunities within the newly acquired assets is the potential Meliwis field development in the Madura Offshore PSC. The Meliwis field will be developed using an unmanned single well head platform that will be tied back to the Maleo production platform. A final investment decision will be made for the Meliwis development in 4Q 2018 and will convert 31 Bcf (gross) of contingent resource into 2P reserves. The development is expected to cost gross approximately $70 million (Ophir share: $54 million) with production start-up expected twelve months after FID. Gross production is expected to plateau at 25 MMscfd for three years before starting to decline. The development of Meliwis will also extend the economic life of the Maleo field, also in the Madura Offshore PSC, which will lead to monetisation of an additional 7.6Bcf of contingent resource.
Production Outlook
Including the production from Block 12W, Vietnam and the Madura Offshore and Sampang PSCs in Indonesia, we expect (on a proforma basis*) that group production for 2018 will be around 27,500 boepd. Actual production during 2018, incorporating the assets from the completion date of 6 September 2018 is forecast to be approximately 17,000 boepd.
Our Asian production base has low operating costs, averaging $12 per boe, low maintenance capex and consequently is highly cash generative. In our base case, over the next three years we expect production from these assets to average around 25,000 boepd, with variations above and below that number on annual basis depending on timing of maintenance and drilling programmes.
At current commodity prices and after budgeted investment programmes, we expect our production base to generate free cash flow of $300 million over the next three years.
Furthermore there is identified, risked upside across all of our production assets, delivery of which would have the potential to drive production up beyond 25,000 boepd. The near field exploration and development opportunities include:
- Bualuang Phase 5 - Bualuang North - Kerendan Phases 2 and 3 - Meliwis development - Paus Biru near field exploration
LNG Assets
The Fortuna development suffered a setback in 1H 2018 with the dissolution of OneLNG and the subsequent effective withdrawal of Schlumberger from the Fortuna project. We continue to work to realise value for shareholders whilst we are in possession of the licence. Given the uncertainty around the value we can ultimately realise from Fortuna, we have impaired the asset to a carrying value of $300 million held on our balance sheet at the period-end.
In Tanzania, there have been no material steps forward although the government is running a tender process for advisors to engage with the industry and help with a view to delivering the project.
Exploration
In the short term, exploration will focus on near field opportunities with the rest of the portfolio being evaluated to minimise capital exposure to long payback, frontier exploration until the company has become self-sustaining.
The most immediate exploration well will be the Bualuang North well that is expected to be drilled in October. The well is expected to cost less than $1.5 million on a post-tax (dry hole cost) basis and is targeting between one and five million barrels of prospective resources with a greater than 50% chance of success. In the event of success, the intention is to tie Bualuang North back to the existing production facilities and any discovery of over one million barrels is expected to payback in less than 18 months.
In Equatorial Guinea, we were awarded an 80% operated interest in Block EG-24, we subsequently farmed out a 40% interest to Kosmos Energy who in return will shoot a block wide 3D seismic survey, for which Ophir is fully cost carried, and partially carried on the cost of a well if a decision to drill is made. The 3D survey commenced in May and is 63% complete.
*on a proforma basis assuming accounting for acquisition from the effective date of 1 January 2018.
Financial Review
Sources and Uses of Funds Summary
Units 1H 2018 1H 2017 FY 2017
Total Production:
-------- -------- --------
Bualuang Mboepd 7.8 8.1 8.4
------------- -------- -------- --------
Kerendan Mboepd 2.3 1.7 2.1
------------- -------- -------- --------
Sinphuhorm Mboepd 1.3 1.5 1.2
------------- -------- -------- --------
Net Sources of Funds:
-------- -------- --------
Revenue $'millions 102.0 88.3 188.5
------------- -------- -------- --------
Kerendan Take or
Pay(1) $'millions (0.1) 2.0 -
------------- -------- -------- --------
Cost of production
(2) $'millions (30.4) (36.0) (70.0)
------------- -------- -------- --------
Investment Income $'millions 1.8 2.6 4.2
------------- -------- -------- --------
Income Tax Charge $'millions (30.4) (17.0) (32.6)
------------- -------- -------- --------
Net funds flow from
production (3) $ 'millions 42.9 39.9 90.0
------------- -------- -------- --------
Net Uses of Funds:
-------- -------- --------
Capital Expenditure
(including pre-licence
expenditure) (3) $'millions 49.7 45.4 101.1
------------- -------- -------- --------
Net administration
cost $'millions 6.5 5.8 11.3
------------- -------- -------- --------
Net interest cost $'millions 6.6 7.0 13.2
------------- -------- -------- --------
Net uses of funds
(3) $'millions 62.8 58.2 125.6
------------- -------- -------- --------
Financing:
-------- -------- --------
Closing net cash $'millions 75.3 129.9 117.1
------------- -------- -------- --------
Closing debt $'millions 104.7 106.6 106.7
------------- -------- -------- --------
Undrawn Debt Facilities $'millions 190.7 177.5 203.5
------------- -------- -------- --------
Closing liquidity $'millions 370.7 414.0 427.3
------------- -------- -------- --------
1. Represents the movement on the non-current trade and other payables balance of $(0.1)m (FY17:$(4.9)m, 1H17:$5.5m) and the current trade and other payables balance, take or pay portion of nil (FY17:$4.9m, HY17 $(3.5)m)
2. Includes operating expenses, royalty payments and movement in inventories of oil.
3. Net funds flow from production and net uses of funds have been presented to eliminate the effects of short-term working capital adjustments
4. Adjusted to eliminate non-cash movements for decommissioning of $0.5m (FY17: $0.7m, HY17: $0.5m)
Net Sources of Funds
Working interest production from Kerendan and Bualuang for the period averaged 10,100 boepd and generated revenues of $102 million, up $14 million or 16% on the same period in 2017. As a result of our low unit operating costs of $12 per boe (HY'17: $14 per boe), the assets generated $43 million of net funds flow from production (HY'17: $40 million), or $23 per boe (HY'17: $21 per boe).
The Kerendan field generated revenue of $11 million (HY'17: $8 million) at an average gas price of $5.43 per Mscf (HY'17: $5.23). Revenue from the Bualuang field totalled $95 million (HY'17: $81 million) or $67 per bbl for the period compared to $50 per bbl for the same period last year. The increased average realised oil price arose from both a higher Dubai price, and a reduction in 2H 2017 of the contracted Dubai discount from $1.65 per bbl to $1.23 per bbl. From August 2018 the discount is further reduced to $1.08 per bbl.
In late 2017, we implemented a commodity price hedging programme in respect of the full calendar year 2018. A Brent-swap was purchased at an average price of $60 per bbl and a call was purchased at an average price of $68 per bbl, both trades for 3,200 bopd. The hedge represents approximately 27% of forecast 2018 production.
In addition, the Sinphuhorm field contributed $2 million of investment income (HY'17: $3 million), the asset realising a gas price of $5.26 per Mscf (HY'17: $4.36 per Mscf).
Net Uses of Funds
Capital expenditure during the period was held constant against the same period last year and totalled $50 million. The primary investments during 1H 2018 comprised:
o Mexico exploration $11 million o West Bangkanai seismic $4 million o Fortuna $6 million o Bualuang Phase 4 $10 million o Kerendan seismic $4 million
The original capital expenditure guidance for 2018 included $55 million of post-FID spend on the Fortuna project that has been deferred now until we have greater certainty on phasing. The Board has provisioned up to $150 million for forward expenditure on Fortuna ahead of first gas and has no intention at this time of increasing the amount.
Full year 2018 capital expenditure forecast, including the newly acquired Asian assets, remains, on a full year proforma basis, as previously guided at approximately $145 million (excluding the acquisition costs of the Santos assets). Capital expenditures for 2H 2018, comprises predominantly:
-- Mexico exploration $13 million -- Bualuang Phase 4 development $35 million -- Santos acquired assets $25 million
Longer-term, outstanding financial commitments to host governments for exploration total $85 million, to be discharged in a five-plus years' programme. In line with our objective to only pursue selective exploration, steps will be taken to minimise and reduce this exposure where we can going forward.
Balance sheet
The reserves based lending facility was undrawn at the end of the period with a borrowing base amount available of $191 million. This has been subsequently drawn to an amount of $150 million, in part to fund the acquisition of the Santos package of assets.
Net interest charges in the period of $7 million arose predominantly on our net outstanding $104 million Nordic Bond. The average cost of borrowing for 1H 2018 was 10% (HY'17: 10%).
We ended the period with a cash and cash equivalents of $180 million, and with our undrawn reserves based lending facility, total liquidity available at 30 June 2018 of $371 million (HY 2017: $414 million).
With the increase to operating cash flow, forecast net debt at year-end 2018 is revised to $110 million, and with our current 2018 refinance plans gross liquidity to $260 million. Year-end liquidity (gross debt / EBITDAX) and gearing (debt / debt + equity) ratios are forecast to be very modest at below 2.0 and 25% respectively.
As part of the mid-year reporting process, the carrying value of all assets was reviewed. We concluded for Fortuna that, although we continue to work to deliver value, uncertainty remains as to whether this can be realised before the licence expires. We have consequently impaired the asset to a carrying value of $300 million held on our balance sheet at 30 June 2018. This carrying value of $300 million is not based on any one specific outcome but has been determined by considering different scenarios and a range of possible outcomes. Once we reach an outcome, a further impairment may be required. In addition to the impairment of Fortuna, we also wrote-off exploration expenses in 1H 2018 of $48 million (HY'17: $77 million), predominantly in respect of interests we hold in Indonesia.
Post balance sheet events
On 6 September 2018 we completed the acquisition of the Southeast Asian package of assets from Santos with an effective date of 1 January 2018. At the time of announcing the transaction in May 2018, the headline consideration was $205 million, which was to be funded partly from an eighteen month bridge facility of up to $130 million, with the balance being met from existing funds.
Through a combination of production outperformance year to date and higher than expected commodity prices, the assets we acquired generated $61 million of net cash in the period between the effective date and the completion date of the transaction reducing the consideration payable to Santos at closing to $144 million, with an effective pay-back of 30% of the acquisition cost in eight months.
The bridge facility was executed on 7 June 2018 with a number of our existing lenders. With the reduced consideration payable to Santos, $103 million of the bridge was drawn-down. The bridge facility with a bullet payment is expected to be refinanced into our longer-term reserves based lending facility in the coming months. On drawing the bridge, we entered into an additional commodity price hedging programme against the Chim Sao asset comprising buying of a swap at an average strike price of $70 per bbl and buying a call at an average strike price of $78 per bbl, both trades for 2,000 bbl per day, for the period 6 September 2018 to 5 September 2019.
Financial Guidance
Full year 2018 guidance is revised as follows:
Units Proforma IFRS Basis(2)
Basis(1)
FY 2018 FY 2018
-------------- ---------- -------------
Production (Mboepd) 27.5 17.0
-------------- ---------- -------------
Net funds flow from production ($'millions) 210 130
-------------- ---------- -------------
Acquisition cost (with effective
date of 1 January 2018) ($'millions) 205 144
-------------- ---------- -------------
Capital expenditure ($'millions) 145 125
-------------- ---------- -------------
Net debt ($'millions) 110 110
-------------- ---------- -------------
Gross liquidity (cash and undrawn
debt facility) ($'millions) 260 260
-------------- ---------- -------------
1. Full year 2018 pro forma basis assuming accounting for the Santos acquisition from the effective date of 1 January 2018.
2. Full year 2018 IFRS basis with acquisition accounting for the transaction from the closing date of 6 September 2018, and as will be reported in the company's consolidated 2018 financial statements
.
Looking forward to 2019, full year production is forecast at 25,000 boepd against which we expect to generate operating cash flow, at an average Brent oil price of $73 per bbl, of $200 million.
Our pre-budget estimate of forecast 2019 capital expenditure is $175 million. Commitment exploration expenditure is forecast at $50 million and in line with our objective to only pursue selective exploration, steps will be taken to minimise and reduce this exposure where we can. Maintenance and sanctioned development capital expenditure, including Bualuang Phase 4 development, is forecast at $100 million.
Additionally, whilst the board has provisioned up to $150 million for post-FID spend on Fortuna, nothing is included in this estmate pending a firm outcome on Fortuna being determined and capital expenditure phasing being known with more certainty. On this basis, we expect to see at year-end 2019 net debt remain approximately unchanged at $105 million with gross liquidity at $215 million. Year-end 2019 liquidity and gearing ratios are forecast to remain at 2.0 and 25% respectively.
Outlook
As outlined in the separate release today, the focus going forward is on building a strong, cash generative production and development base which will serve as a platform for further growth and shareholder returns. The addition of the Santos package of assets was the first step in this direction. Delivering material free cash flow to drive net asset growth and returns to shareholders is the priority.
Furthermore, we will look to selectively evaluate and action opportunities for consolidation that could rapidly and effectively deliver our objectives of materiality, sustainability and shareholder returns.
Our LNG options have potential value that is not today reflected in our share price despite a rapidly improving LNG landscape. We will consider options to unlock this value and intend to ensure that our shareholders share appropriately in any value subsequently realised.
We are taking further action to right size the cost structure of the business. We propose to further downsize our London office, following workforce consultation, and within 12 months establish a fit for purpose Asian based HQ, which will serve as the hub for our ongoing business, generating material cost savings.
The Board believes that these actions will create a focused, efficient business generating a significant amount of free cash flow. This will provide a strong platform for the new CEO who will be able to determine, with the Board, an appropriate strategy for capital allocation to further grow the business and maximise value creation.
Risk Management
The principal risks and uncertainties affecting Ophir are described in the risk management section of the Ophir Annual Report 2017 (pages 26-31) and are summarised below.
-- External Risks: Low commodity price and adverse market sentiment towards the E&P sector, global economic volatility, capital constraints, legal compliance regulatory or litigation risk, stakeholder sentiment, political risk, climate change.
-- Strategic Risks: Investment decisions, inadequate resource and reliance on key personnel.
-- Operational Risks: HSE and security incident, drilling operations risk, discovery risk and success rate, IT risk.
-- Financial Risks: Inability to fund exploration work programmes, counterparty credit risk, cost and capital spending, interest rate and foreign exchange risk.
Responsibility Statement
The Directors confirm that to the best of their knowledge:
a the condensed set of financial statements has been prepared in accordance with IAS 34 "Interim Financial Reporting";
b the half year report includes a fair review of the information required by DTR 4.2.7R (indication of important events during the first six months and description of principal risks and uncertainties for the remaining six months of the year);
c the half year report includes a fair review of the information required by DTR 4.2.8R (disclosure of related parties' transactions and changes therein);
The Directors of Ophir Energy plc are as listed in the Company Information section at the back of this report.
By order of the Board
Alan Booth
Interim Chief Executive Officer
12 September 2018
Independent Review Report to Ophir Energy plc
Introduction
We have been engaged by the Company to review the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2018 which comprises condensed consolidated income statement and statement of comprehensive income, the condensed consolidated statement of financial position, the condensed consolidated statement of changes in equity, the condensed consolidated statement of cash flows and the related explanatory notes that have been reviewed. We have read the other information contained in the half yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed set of financial statements.
This report is made solely to the company in accordance with guidance contained in International Standard on Review Engagements 2410 (UK and Ireland) "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company, for our work, for this report, or for the conclusions we have formed.
Directors' Responsibilities
The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.
As disclosed in note 2 the annual financial statements of the group are prepared in accordance with IFRSs as adopted by the European Union. The condensed set of financial statements included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, "Interim Financial Reporting", as adopted by the European Union.
Our Responsibility
Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the half-yearly financial report based on our review.
Scope of Review
We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, "Review of Interim Financial Information Performed by the Independent Auditor of the Entity" issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.
Conclusion
Based on our review, nothing has come to our attention that causes us to believe that the condensed set of financial statements in the half-yearly financial report for the six months ended 30 June 2018 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure Guidance and Transparency Rules of the United Kingdom's Financial Conduct Authority.
Ernst & Young LLP
London
12 September 2018
Condensed consolidated income statement and statement of comprehensive income
Six months ended 30 June 2018
6 Months 6 Months
Ended Ended
30 June 30 June Year ended
2018 2017
31 December
(Unaudited) (Unaudited) 2017
Notes $'000 $'000 $'000
Consolidated income statement
Continuing operations
Revenue 4 102,066 88,293 188,527
Cost of sales 5a (67,827) (69,386) (147,577)
------------- ------------- --------------
Gross profit 34,239 18,907 40,950
Share of profit of investments
accounted for using the equity
method 18 1,818 2,560 4,181
Impairment reversal of oil
and gas properties - 23,681 23,681
Impairment of investments
accounted for using the equity
method - - (7,800)
Impairment of non-current
assets held for sale 8 (309,887) - -
Exploration expenses 5b (52,983) (77,126) (91,836)
General & administration expenses 5c (6,464) (5,839) (11,279)
Other operating (expenses)/income 5d 27 (1,361) (11,699)
Operating loss (333,250) (39,178) (53,802)
Net finance expense 6 (7,565) (6,463) (12,907)
Other financial gains 160 - 2,300
Loss from continuing operations
before taxation (340,655) (45,641) (64,409)
Taxation (expense)/benefit 7 (34,753) (38,977) (47,383)
============= ============= ==============
Loss from continuing operations
for the period attributable
to: (375,408) (84,618) (111,792)
============= ============= ==============
Equity holders of the Company (375,408) (84,618) (111,792)
Non-controlling interest - - -
------------- ------------- --------------
(375,408) (84,618) (111,792)
------------- ------------- --------------
Earnings per share
Basic - Loss for the period
attributable to equity holders (15.8)
of the Company (53.1) cents (12.0) cents cents
Diluted - Loss for the period
attributable to equity holders (15.8)
of the Company (53.1) cents (12.0) cents cents
Condensed consolidated income statement and statement of comprehensive income
Six months ended 30 June 2018 (continued)
6 Months 6 Months
Ended ended
30 June 30 June Year ended
2018 2017
31 December
(Unaudited) (Unaudited) 2017
Notes $'000 $'000 $'000
Consolidated statement of comprehensive
income
Loss from continuing operations
for the period (375,408) (84,618) (111,792)
Other comprehensive (loss)/income
Other comprehensive (loss)/income
to be reclassified to profit or
loss in subsequent periods:
Exchange differences on retranslation
of foreign operations net of tax (31) - -
Cash flow hedges marked to market (5,186) - (5,882)
Cash flow hedges reclassified to
the income statement 4,459 - -
============= ============= ==============
Other comprehensive income/(loss)
for the period, net of tax (758) - (5,882)
============= ============= ==============
Total comprehensive loss for the
period, net of tax attributable
to:
Equity holders of the Company (376,166) (84,618) (117,674)
Non-controlling interest - - -
------------- ------------- --------------
(376,166) (84,618) (117,674)
============= ============= ==============
Condensed consolidated statement of financial position
As at 30 June 2018
As at As at As at
30 June
30 June 2018 2017 31 December
(unaudited) (unaudited) 2017
Notes $'000 $'000 $'000
Non-current assets
Exploration and evaluation
assets 9 223,736 240,462 247,944
Oil and gas properties 10 676,044 719,350 699,669
Other property, plant
and equipment 1,718 2,811 2,211
Other long term receivables 19,948 22,541 21,205
Investments accounted
for using the equity
method 18 123,445 130,388 120,964
-------------- ------------- -------------
1,044,891 1,115,552 1,091,993
-------------- ------------- -------------
Current assets
Assets classified as
held for sale 8 300,000 596,999 604,432
Inventory 11 39,543 40,718 40,647
Trade and other receivables 41,459 39,821 24,656
Taxation receivable 9,128 9,124 9,125
Cash and cash equivalents 12 180,036 236,523 223,779
570,166 923,185 902,639
-------------- ------------- -------------
Total assets 1,615,057 2,038,737 1,994,632
-------------- ------------- -------------
Current liabilities
Trade and other payables 13 (43,531) (73,304) (52,374)
Taxation payable (29,003) (19,016) (30,282)
Provisions 16 (8,889) (10,017) (9,399)
Derivative financial
instruments (5,116) - (3,582)
============== ============= =============
(86,539) (102,337) (95,637)
============== ============= =============
Non-current liabilities
Other Payables 13 (15,169) (15,866) (15,279)
Interest-bearing bank
borrowings 14 - - -
Bonds payable 15 (104,733) (106,651) (106,651)
Deferred tax liability 7d (268,894) (271,575) (264,491)
Provisions 16 (52,503) (51,725) (51,265)
(441,299) (445,817) (437,686)
-------------- ------------- -------------
Total liabilities (527,838) (548,154) (533,323)
-------------- ------------- -------------
Net assets 1,087,219 1,490,583 1,461,309
============== ============= =============
Condensed consolidated statement of financial position
As at 30 June 2018 (continued)
As at As at As at
30 June
30 June 2018 2018 31 December
(unaudited) (unaudited) 2017
Notes $'000 $'000 $'000
Capital and reserves
Called up share capital 17 3,061 3,061 3,061
Reserves 19 1,084,158 1,487,802 1,458,528
========== ========== ==========
Equity attributable
to equity shareholders
of the Company 1,087,219 1,490,863 1,461,589
Non-controlling interest - (280) (280)
Total equity 1,087,219 1,490,583 1,461,309
========== ========== ==========
Approved by the Board on 12 September 2018
Alan Booth
Interim Chief Executive Officer
Condensed consolidated statement of changes in equity
Six months ended 30 June 2018
Called Non-controlling
up share Treasury Other reserves interest
capital shares (1) Total equity
$'000 $'000 $'000 $'000 $'000
============================
As at 1 January 2017 3,061 (153) 1,572,449 (280) 1,575,077
Loss for the period,
net of tax - - (84,618) - (84,618)
Other comprehensive
income, net of tax - - - - -
========== ========= =============== ================= =============
Total comprehensive
loss, net of tax - - (84,618) - (84,618)
Exercise of options - - - - -
Share-based payment - - 124 - 124
========== ========= =============== ================= =============
As at 30 June 2017
(Unaudited) 3,061 (153) 1,487,955 (280) 1,490,583
Loss for the period,
net of tax - - (27,174) - (27,174)
Other comprehensive
loss, net of tax - - (5,882) - (5,882)
========== ========= =============== ================= =============
Total comprehensive
loss, net of tax - - (33,056) - (33,056)
Exercise of options - 1 - - 1
Share-based payment - - 3,781 - 3,781
========== ========= =============== ================= =============
As at 31 December
2017 3,061 (152) 1,458,680 (280) 1,461,309
Loss for the period,
net of tax - - (375,408) - (375,408)
Other comprehensive
income, net of tax - - (758) - (758)
========== ========= =============== ================= =============
Total comprehensive
loss, net of tax - - (376,166) - (376,166)
Dispoal of Non-Controlling
Interest - - (280) 280 -
Exercise of options - 3 - - 3
Share-based payment(2) - - 2,073 - 2,073
========== ========= =============== ================= =============
As at 30 June 2018
(Unaudited) 3,061 (149) 1,084,307 - 1,087,219
(1) Refer to note
20 - Other reserves
(2) Refer to note
5c
Condensed consolidated statement of cash flows
Six months ended 30 June 2018
6 Months 6 Months Year ended
Ended ended
30 June 30 June 31 December
2018 2017 2017
(unaudited) (unaudited) $'000
Notes $'000 $'000
Operating activities
Loss before taxation (340,655) (45,641) (64,409)
Adjustments to reconcile loss before
taxation to net cash provided by
operating activities
Exploration expenses 5b 47,993 77,126 76,108
Impairment of non-current assets
held for sale 8 309,887 - -
Depreciation and amortisation 37,777 34,508 79,230
Net Impairment on reversal on oil
and gas assets and gain on disposal
of fixed assets and investments
in minority interest (174) (23,607) (16,061)
Share of profits from joint ventures 18 (1,818) (2,560) (4,181)
Net charge for interest 6 7,303 7,649 14,724
Net foreign currency losses/(gains) 6 262 (1,062) (1,817)
Share-based payment expense 5c 2,073 124 3,905
(Decrease)/increase in provisions 221 4,590 9,381
----------------------------------------- ------ ------------- ------------- -------------
Cash flow from operation before
working capital adjustments 62,869 51,127 96,880
----------------------------------------- ------ ------------- ------------- -------------
Increase in inventories 1,594 4,331 7,123
(Decrease)/increase in other current
and non-current payables (297) 3,241 1,962
(Increase)/decrease in other current
and non-current assets (14,878) (7,177) 10,147
----------------------------------------- ------ ------------- ------------- -------------
Cash generated from operations 49,288 51,522 116,112
----------------------------------------- ------ ------------- ------------- -------------
Interest received 1,075 983 2,057
Income taxes paid (31,668) (5,147) (9,485)
----------------------------------------- ------ ------------- ------------- -----------------
Net cash (used in)/generated by
operating activities 18,695 47,358 108,684
----------------------------------------- ------ ------------- ------------- ----------------- Investing activities Additions to Exploration and Evaluation assets (37,566) (52,347) (95,827) Additions to property, plant and equipment (14,841) (20,250) (47,179) Dividends received from joint ventures 18 951 3,126 6,523 Funding provided to joint ventures 18 (1,614) (218) (370) Proceeds from disposals of assets - - 428 Net cash used in investing activities (53,070) (69,689) (136,425) ------------------------------------------------- ------------- ------------- ----------------- Financing activities Interest paid (9,564) (7,908) (15,217) Repayment of debt - (93,656) (93,656) Net issue/(repurchase) of shares 3 - 1 Net cash used in financing activities (9,561) (101,564) (108,872) ------------------------------------------------- ------------- ------------- ----------------- Currency translation differences relating to cash and cash equivalents 193 (6) (32) ------------------------------------------------- ------------- ------------- ----------------- Decrease in cash and cash equivalents (43,743) (123,901) (136,645) ------------------------------------------------- ------------- ------------- ----------------- Cash and cash equivalents at beginning of period 223,779 360,424 360,424 Cash and cash equivalents at end of period 180,036 236,523 223,779 ------------------------------------------------- ------------- ------------- -----------------
Notes to the condensed interim financial statements
1 Corporate information
Ophir Energy plc (the 'Company' and ultimate parent of the Group) is a public limited company domiciled and incorporated in England and Wales. The Company's registered offices are located at 123 Victoria Street, London SW1E 6DE.
The principal activity of the Group is the development of offshore oil and gas exploration assets. The Company has an extensive and diverse portfolio of exploration interests across Africa and Southeast Asia.
The Income Statement and Statement of Comprehensive Income, Statement of Financial Position, Statement of Changes in Equity, Statement of Cash Flows and associated Notes to the Financial Statements for the financial year ended 31 December 2017 included in the 30 June 2018 half yearly financial report do not constitute the Group's statutory accounts, as defined under section 435 of the Companies Act 2006. The Group's statutory financial statements for the financial year ended 31 December 2017 have been audited by the Group's external auditor and lodged with the United Kingdom Companies House. The auditor's opinion on these accounts was unqualified and did not contain a statement under either Section 498(2) or 498(3) of the Companies Act 2006.
The Group's condensed consolidated interim financial statements are unaudited but have been reviewed by the auditors and their report to the Company is included on page 11-12. These condensed consolidated interim financial statements of the Group for the six months ended 30 June 2018 were approved and authorised for issue by the Board of the Directors on 12 September 2018.
2 Basis of preparation and significant accounting policies 2.1 Basis of preparation
The unaudited condensed consolidated interim financial statements for the six months ended 30 June 2018 included in this interim report has been prepared in accordance with International Accounting Standard 34 'Interim Financial Reporting', as adopted by the European Union, and have been prepared on the basis of the accounting policies set out in the Group's Annual Report for year ended 31 December 2017.
The unaudited condensed consolidated interim financial statements are prepared on a going concern basis as the Directors, having considered available relevant information, have a reasonable expectation that the Group has adequate resources to continue to operate for the foreseeable future.
The consolidated financial statements have been prepared on a historical cost basis and are presented in US Dollars rounded to the nearest thousand dollars ($'000) except as otherwise indicated.
Comparative figures for the period to 31 December 2017 are for the year ended on that date.
The interim financial statements do not include all the information and disclosures required in the annual financial statements, and should be read in conjunction with the consolidated financial statements in the Ophir Energy plc Annual Report and Accounts for the year ended 31 December 2017. The accounting policies adopted in the preparation of the interim financial statements, the significant judgements made by management in applying these policies, and key sources of estimation uncertainty are consistent with those followed in the preparation of the Group's financial statements for the year ended 31 December 2017, with the exception of the implementation of IFRS 9 'Financial Instruments' and IFRS 15 'Revenue from Contracts with Customers' from 1 January 2018.
2.2 New International Financial Reporting Standards adopted
Ophir adopted IFRS 9 'Financial Instruments' and IFRS 15 'Revenue from Contracts with Customers' with effect from 1 January 2018. Information on the implementation of new accounting standards is included in Ophir Annual Report - Note 1 Basis of preparation and significant accounting policies, and also outlined below:
Notes to the condensed interim financial statements (continued)
Basis of preparation - New International Financial Reporting Standards adopted (continued)
IFRS 9 'Financial Instruments'
IFRS 9 provides a single classification and measurement approach for financial assets that reflects the business model in which they are managed and their cash flow characteristics. Under the new standard the group's financial assets are classified as measured at amortised cost, fair value through profit or loss, or fair value through other comprehensive income. For financial liabilities the existing classification and measurement requirements of IAS 39 are largely retained. Whilst financial assets have been reclassified into the categories required by IFRS 9, the group has not identified any impacts on the measurement of its financial assets and financial liabilities as a result of the classification and measurement requirements of the new standard. Trade receivables are held to collect contractual cash flows and are expected to give rise to cash flows representing solely payments of principal and interest. Thus, the Group has continued to measure these at amortised cost under IFRS 9.
Under IFRS 9, impairments of financial assets classified as measured at amortised cost are recognised on an expected loss basis which incorporates forward-looking information when assessing credit risk. Movements in the expected loss reserve are recognised in profit or loss. Due to the short-term nature and high quality of the financial assets, the Group has not recognised any impacts on the adoption of IFRS 9.
The hedge accounting requirements of IFRS 9 have been simplified and are more closely aligned to an entity's risk management strategy. Under IFRS 9 all existing hedging relationships will qualify as continuing hedging relationships. IFRS 9 also introduces a new way of treating fair value movements on the time value of certain hedging instruments. Whereas under IAS 39 these movements were recognised in profit or loss, under IFRS 9 they are initially recognised in equity to the extent that they relate to the hedged item. An adjustment to the 2018 opening balance sheet has been made to transfer $2.3 million of gains from retained earnings to the hedging reserve for relevant hedging instruments existing on transition (see note 20). As permitted by IFRS 9 comparatives were not restated.
IFRS 15 'Revenue from Contracts with Customers'
Under IFRS 15, revenue from contracts with customers is recognised as or when the group satisfies a performance obligation by transferring a promised good or service to a customer. A good or service is transferred when the customer obtains control of that good or service. The transfer of control of oil and gas sold by the group coincides with title passing to the customer and the customer taking physical possession. The group satisfies its performance obligations at a point in time. The accounting for revenue under IFRS 15 does not, therefore, represent a change from the group's previous practice for recognising revenue from sales to customers.
An analysis of revenue from contracts with customers by product is presented in note 4 and by product and segment in note 3.
2.3 Update to accounting judgements - Balance Sheet classification and recoverability of asset carrying values - non-current assets held for sale
The classification of the group's share of the Block R licence in Equatorial Guinea as a non-current asset held for sale was reviewed during the first half of 2018. Despite the dissolution of OneLNG and the expiry of the current licence on 31 December 2018, management continue to work to deliver value from the licence. Financing for the project has not yet been secured resulting in delay to achieving FID. Discussions with potential counterparties to unlock the value of Fortuna are ongoing and the Company remains committed to a plan with an active programme in place to locate a buyer. It is due to this that management believe the classification of the Block R licence as a non-current asset held for sale continues to meet the IFRS 5 criteria. However, given the increased uncertainty as outlined above, future cash flows have been adjusted for the specific risks. Details of the impairment charge related to non-current assets held for sale are shown in note 8.
For further information on the group's accounting policy on significant estimates and judgements relating to non-current assets held for sale, see Ophir Annual Report 2017 - Financial statements - Note 2.4 Significant accounting judgements, estimates and assumptions.
3 Segmental analysis
The Group's reportable and geographical segments are Africa, Asia and Other. Other relate
substantially to activities in the UK.
Segment revenues and results
The following is an analysis of the Group's revenue and assets by reportable segment:
Six months ended 30 June 2018
Africa Asia Other Total
$'000 $'000 $'000 $'000
Oil revenue from contracts with customers - 95,408 - 95,408
Gas revenue from contracts with customers - 11,117 - 11,117
Loss relating to oil derivatives - (4,459) - (4,459)
Operating profit/(loss) (310,095) (10,995) (12,160) (333,250)
----------- ---------- --------- ----------
Net finance (expense) and other financial gains (183) (175) (7,047) (7,405)
Profit/(loss) before tax (310,278) (11,170) (19,207) (340,655)
Taxation (1,341) (33,412) - (34,753)
----------- ---------- --------- ----------
Profit/(loss) after tax (311,619) (44,582) (19,207) (375,408)
Total assets 429,225 1,077,257 108,575 1,615,057
----------- ---------- --------- ----------
Six months ended 30 June 2017
Africa Asia Other Total
$'000 $'000 $'000 $'000
Oil revenue from contracts with customers - 80,753 - 80,753
Gas revenue from contracts with customers - 7,540 - 7,540
Operating profit/(loss) (58,071) 35,848 (16,955) (39,178)
----------- ---------- --------- ----------
Net finance (expense)/income 120 (302) (6,281) (6,463)
Profit/(loss) before tax (57,951) 35,546 (23,236) (45,641)
Taxation 4,891 (43,865) (3) (38,977)
----------- ---------- --------- ----------
Profit/(loss) after tax (53,060) (8,319) (23,239) (84,618)
Total assets 725,279 1,128,047 185,411 2,038,737
----------- ---------- --------- ----------
year ended 31 December 2017
Africa Asia Other Total
$'000 $'000 $'000 $'000
Oil revenue from contracts
with customers - 169,461 - 169,461
Gas revenue from contracts
with customers - 19,066 - 19,066
Operating profit/(loss) (58,783) 34,604 (29,623) (53,802)
--------- ---------- --------- ----------
Net finance (expense)/income
and other financial gains 157 (901) (9,863) (10,607)
Profit/(loss) before tax (58,626) 33,703 (39,486) (64,409)
Taxation 5,296 (52,676) (3) (47,383)
--------- ---------- --------- ----------
Profit/(loss) after tax (53,330) (18,973) (39,489) (111,792)
Total assets 729,337 1,113,555 151,740 1,994,632
--------- ---------- --------- ----------
6 Months Year ended
6 Months ended ended
30 June 31 December
30 June 2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
4 Revenue
Sales of crude oil 95,408 80,753 169,461
Sales of gas 11,117 7,540 19,066
---------------- -------------- ----------------
Revenue from contracts with
customers 106,525 88,293 188,527
---------------- -------------- ----------------
Loss relating to oil derivatives (4,459) - -
102,066 88,293 188,527
================ ============== ================
5 Operating profit/(loss) before
taxation
The Group operating profit/(loss) from continuing operations
before taxation is stated after charging/(crediting):
(a) Cost of sales:
- Operating costs 21,660 24,418 48,864
- Royalty payable 7,242 7,189 14,057
* Depreciation and amortisation of oil and gas
properties (note 10) 37,333 33,445 77,529
- Movement in inventories
of oil 1,592 4,334 7,127
---------------- -------------- ----------------
67,827 69,386 147,577
================ ============== ================
(b) Exploration expenses:
* Pre licence and other exploration costs 4,990 7,909 15,728
* Exploration expenditure written off (note 9) 47,926 69,217 76,652
* Exploration inventory provision expense/(reversal) 67 - (544)
================ ============== ================
52,983 77,126 91,836
================ ============== ================
(c) General & administration
expenses include:
* Operating lease payments - minimum lease payments 1,492 1,602 3,424
* Share-based payment/(release) 2,073 124 3,905
================ ============== ================
3,565 1,726 7,329
================ ============== ================
(d) Other operating (income)/expenses:
* (Gain)/loss on disposal of minority interest and
fixed assets (174) 74 (180)
* Depreciation of other property plant and
equipment 99 167 288
- Provision for exiting contract
(note 16) - - 8,900
-Restructuring Costs - 1,124 1,935
- Other 48 (4) 756
(27) 1,361 11,699
================ ============== ================
6 Months 6 Months Year ended
ended ended
30 June 31 December
30 June 2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
6 Net finance (expense)/income
Interest income on short-term
bank deposits 1,075 1,107 2,057
Interest expense on long-term
borrowings (7,646) (7,909) (15,218)
Unwinding of discount (note 16) (732) (723) (1,449)
Net foreign currency exchange
(losses)/gains (262) 1,062 1,817
Other Interest (expense)/income - - (114)
---------------- -------------- ----------------
(7,565) (6,463) (12,907)
================ ============== ================
As at As at Year ended
30 June 30 June 31 December
2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
7 Taxation
(a) Taxation charge
Current income tax:
Foreign tax:
Special remuneratory benefit 17,453 5,855 13,696
Other foreign tax 12,968 6,138 13,901
Special remuneratory benefit (24) - -
- adjustment in respect of
prior periods
Foreign tax - adjustment in
respect of prior periods (10) 4,997 4,997
-------------
Total current income tax charge 30,387 16,990 32,594
------------- ------------- -------------
Deferred tax:
Special remuneratory benefit 9,886 31,094 27,378
Other foreign tax (5,520) (9,107) (12,589)
Total deferred tax (credit)/charge 4,366 21,987 14,789
------------- ------------- -------------
Total tax charge in the income
statement 34,753 38,977 47,383
============= ============= =============
Special Remuneratory Benefit (SRB) is a tax that arises on one
of the Group's assets, Bualuang in Thailand at rates that vary
from zero to 75% of annual petroleum profit depending on the
level of annual revenue per cumulative metre drilled. The current
rate for SRB for 2018 was 29% (30 June 2017: 16%, 31 December
2017: 18%). Petroleum
profit for the purpose of SRB is calculated as revenue less a
number of deductions including operating costs, royalty, capital
expenditures, special reduction (an uplift of certain capital
expenditures) and losses brought forward.
As at As at Year ended
30 June 30 June 31 December
2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
Taxation (continued)
(b) Reconciliation of the total
tax charge
The tax charge recognised in the income statement is reconciled
to the Group's weighted average tax rate of 47% (30 June 2017:
49%, 31 December 2017: 48%). The differences are reconciled below:
Loss from operations before
taxation (340,655) (45,641) (64,409)
============= ============= =============
Loss from operations before
taxation multiplied by the
Group's applicable weighted
average tax rate of 47% (30
June 2017: 49% , 31 December
2017: 48%)(1) (161,026) (22,140) (31,175)
Tax effect of SRB 13,657 18,475 20,537
Tax effect of share of profit
of investments accounted for
using the equity method (909) (1,280) (2,091)
Non-deductible (income)/expenditure 129,269 20,498 27,991
Effect of different tax rates
on loss making jurisdictions 46,732 20,868 30,256
Unrecognised deferred tax assets 4,559 1,964 1,096
Prior year adjustments 1,433 (5,581) (5,580)
Other adjustments 1,038 6,173 6,349
Total tax (credit)/charge in
the income statement 34,753 38,977 47,383
============= ============= =============
(1) Loss making jurisdictions have been disregarded in the calculation of weighted average tax rate
The taxation charge for SRB for the year can be reconciled to the loss from operations before tax per the consolidated income statement and statement of comprehensive income as follows:
(c) Reconciliation of special remuneratory benefit charge to
loss from operations before taxation
The taxation charge for special remuneratory benefit for the
year can be reconciled to the loss from operations before tax
per the Income Statement as follows:
Loss from operations before
taxation (340,655) (45,641) (64,409)
Add back losses from operations
before taxation for activities
outside of Thailand 380,765 93,686 132,165
------------- ------------- -------------
Profit from operations before
taxation for activities in
Thailand 40,110 48,045 67,756
Deduct share of profit from
investments accounted for using
the equity method (1,818) (2,560) (4,181)
------------- ------------- -------------
Profit before taxation for
activities in Thailand 38,292 45,485 63,575
Applicable rate of special
remuneratory benefit 29% 16% 18%
Tax at the applicable rate
of special remuneratory benefit 11,105 7,277 11,443
Change in special remuneratory
benefit average deferred tax
rate 12,895 19,136 13,697
Change in special remuneratory
benefit rate compared to current
special remuneratory benefit
rate 2,222 886 619
Prior year adjustment (24) 7,190 7,191
Other non - deductible costs 1,117 2,460 8,124
Total special remuneratory
benefit charge/(credit) 27,315 36,949 41,074
------------- ------------- -------------
As at As at Year ended
30 June 30 June 31 December
2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
Taxation (continued)
(d) Deferred income tax
Deferred tax balances relate
to the following:
Corporate tax on fixed asset
timing differences (240,987) (241,684) (241,275)
SRB tax on fixed asset timing
differences (32,976) (29,891) (28,033)
Tax Losses 5,069 - 4,817
(268,894) (271,575) (264,491)
------------- ------------- -------------
As at As at Year ended
30 June 2018 30 June 31 Dec
2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
8 Non-current assets held for
sale
Assets
Exploration and evaluation
assets(1) 300,000 596,999 604,432
------------- ------------ -----------
Assets classified as held
for sale 300,000 596,999 604,432
============= ============ ===========
(1) The asset held for sale valuation includes a $310 million impairment of the Block R licence (30 June 2017: nil, 31 December 2017: nil). The triggers for the impairment include the dissolution of the OneLNG joint venture (see paragraph below) and the fact that the current licence period ends 31 December 2018. Given the increased uncertainty, future cash flows have been adjusted for the specific risks. The Block R licence had a recoverable amount of $300m based on management's estimate of fair value less costs to sell, using discounted cash flow techniques incorporating different scenarios and a range of possible outcomes.
On 10 November 2016 Ophir and OneLNG, a joint venture between subsidiaries of Golar LNG Limited and Schlumberger, announced that they had signed a binding Shareholders' Agreement to establish a Joint Venture ("JV") to develop the Fortuna project, in Block R, offshore Equatorial Guinea utilising Golar's FLNG technology. OneLNG and Ophir would have had 66.2% and 33.8% ownership of the JV respectively. The JV would have facilitated the financing, construction, development and operation of the integrated Fortuna project and, from FID, would have owned Ophir's share of the Block R licence. In May 2018, OneLNG made the decision to dissolve itself, however management has continued to classify the Fortuna asset as held for sale. Please see note 2.3 - Update to accounting judgements - Balance Sheet classification and recoverability of asset carrying values - non-current assets held for sale.
As at As at Year ended
30 June 30 June 31 December
2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
9 Exploration and evaluation
assets
Cost
Balance at the beginning of
the period 247,944 310,229 310,229
Additions (1) 29,173 18,286 40,788
Disposal of asset - - (150)
Transfers to oil and gas properties - (10,608) (10,608)
Reclassified as assets held
for sale (5,455) (8,229) (15,663)
Expenditure written-off (2) (47,926) (69,216) (76,652)
Balance at the end of the
period 223,736 240,462 247,944
------------- ------------- -------------
Exploration and evaluation assets (continued)
(1) Additions for the 6 months ended 30 June 2018 were largely
attributable to exploration activities in: Mexico Block 10 ($8.7
million) Equatorial Guinea - Block R ($5.4 million subsequently
reclassified as asset held for sale), West Bangkanai ($3.5 million),
Mexico Block 5 ($2.6 million), Equatorial Guinea (EG-24) ($2.2
million), Tanzania Block 1 ($1.4 million), Myanmar ($1.4 million)
and West Papua IV ($1.2 million).
Additions for the year ended 31 December 2017 included exploration
activities in: Equatorial Guinea - Block R ($15.7 million subsequently
reclassified as an asset held for sale), Myanmar ($2.9 million),
West Papua IV ($4.6 million) and Mexico Block 5 ($8.5 million).
(2) Expenditure written off for the period ended 30 June 2018
was $47.9 million mainly attributable to assets in Indonesia
- West Papua IV ($31 million), North Ganal ($7.7 million) and
Aru (8.4 milllion).
Expenditure written off for the year ended 31 December 2017
was $77 million mainly attributable to Cote d'Ivoire ($32 million)
and Gabon ($32 million). The cash generating unit (CGU) applied
for the purpose of the impairment assessment is the Blocks.
The recoverable amount of each Block was nil. This was based
on management's estimate of value in use. The trigger for expenditure
write off was management's assessment that no further expenditure
on exploration and evaluation of hydrocarbons in the Block was
budgeted or planned within the current licence terms.
The Group generally estimates value in use using a discounted
cash flow model. Future cash flows are discounted to their present
values using a pre-tax discount rate ranging between 8% - 22%
(30 June 2017: 15%, 31 December 2017: 8% - 22%). Adjustments
to cash flows are made to reflect the risks specific to the
CGU.
As at As at Year ended
30 June 30 June 31 December
2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
10 Oil and gas properties
Cost
Balance at the beginning of
the period 929,795 875,278 875,278
Additions 13,708 19,506 43,909
Transfer from Exploration
and evaluation - 10,608 10,608
Balance at the end of the
period 943,503 905,392 929,795
------------- ------------- -------------
Depreciation and amortisation
Balance at the beginning of
the period (230,126) (176,278) (176,278)
Charge for the period (37,333) (33,445) (77,529)
Reversal of impairment(1) - 23,681 23,681
------------- ------------- -------------
Balance at the end of the
period (267,459) (186,042) (230,126)
------------- ------------- -------------
Net book value
Balance at the beginning of
the period 699,669 699,000 699,000
------------- ------------- -------------
Balance at the end of the
period 676,044 719,350 699,669
============= ============= =============
(1) The 2017 impairment reversal was due to further increased
reserves related to the Bualuang infill drilling results in
Thailand which had a recoverable amount of $424m based on management's
estimate of value in use. The discount rate used was 22% (pre-tax).
As at As at Year ended
30 June 30 June 31 December
2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
11 Inventory
Oil and condensates 2,394 6,780 3,988
Materials and consumables 37,149 33,938 36,659
39,543 40,718 40,647
============= ============= =============
The inventory valuation is stated net of a provision of $10.1 million (30 June 2017: 14.6 million, 31 December 2017: 10.1 million) to write inventories down to their net realisable value.
As at As at Year ended
30 June 2018 30 June 2017 31 December
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
12 Cash and cash
equivalents
Cash 109,606 82,398 99,822
Cash equivalents 70,430 154,125 123,957
--------------- -------------- --------------------
180,036 236,523 223,779
=============== ============== ====================
Cash and cash equivalents comprise cash in hand, deposits and
other short-term money market deposit accounts that are readily
convertible into known amounts of cash. The fair value of cash
and cash equivalents is $180 million (30 June 2017: $236.5 million
and 31 December 2017: $223.8 million).
As at As at Year ended
30 June 30 June 2017 31 December
2018
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
13 Trade and other payables -
Current
Trade and other payables 10,642 13,161 9,058
Accruals and deferred income 30,355 53,556 42,219
Payables owed to joint operation
partners 2,534 6,587 1,097
------------ ------------- ------------
43,531 73,304 52,374
============ ============= ============
Trade and other payables -
Non-current
Accruals and deferred income 15,169 15,866 15,279
------------ ------------- ------------
15,169 15,866 15,279
============ ============= ============
As at As at Year ended
30 June 2018 30 June 2017 31 December
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
14 Interest-bearing
bank borrowings
Long term balance
at the beginning
of the period - 83,915 83,915
Short term balance
at the beginning
of the period - 9,741 9,741
Acquisition of
subsidiary - - -
Less: amounts repaid
during the period - (93,656) (93,656)
Less: amounts due
within one year - - -
--------------- ----------------------- -------------
Total borrowings
due after 1 year - - -
=============== ======================= =============
In 2017, Ophir repaid it's outstanding debt on the 2012 reserves
based lending (RBL) facility.
Ophir replaced this facility with a new $250 million RBL facility
secured against the group's producing assets in Southeast Asia.
The RBL has a seven year term and matures on 30 June 2024. In addition
to the committed $250 million, a further $100 million is available
on an uncommitted "accordion" basis. Interest will accrue at a rate
of between 4% and 4.5% plus LIBOR depending on the maturity of the
facility. The new RBL facility is currently undrawn, with an available
facility as at 30/06/2018 of $191 million. Of the $5.8 million of
transaction costs in relation to the facility, $4.1 million have
been deferred within 'other long term receivables' on the balance
sheet and are being amortised over the term of the facility.
As at As at Year ended
30 June 2018 30 June 2017 31 December
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
15 Bonds payable
Balance at the
beginning of
the period 106,651 106,651 106,651
Coupon interest
charged 5,396 5,109 10,218
Interest paid (7,314) (5,109) (10,218)
--------------- -------------- -----------------------------
104,733 106,651 106,651
=============== ============== =============================
The unsecured callable bonds were issued by Salamander Energy
plc in December 2013 at an issue price of $150 million. The bonds
have a term of six years and one month and will be repaid in full
at maturity. The bonds carry a coupon of 9.75% and were issued
at par.
Decommissioning
and restoration Litigation
of oil and and other Total
gas assets claims Other provisions $'000
$'000 $'000 $'000
Provisions
16
As at 30 June 2017 51,725 4,675 5,342 61,742
----------------- ----------- ----------------- ---------------
Arising during the
period - - - -
Utilised/paid - (4,675) (4,835) (9,510)
Unwinding of discount
(note 6) 726 - - 726
Amounts released - - - -
Remeasurement (1,194) - - (1,194)
Additions - - 8,900 8,900
As at 1 January 2018 51,257 - 9,407 60,664
----------------- ----------- ----------------- ---------------
Arising during the
period - - - -
Utilised/paid - - (510) (510)
Unwinding of discount
(note 6) 732 - - 732
Amounts released - - - -
Additions 506 - - 506
As at 30 June 2018 52,495 - 8,897 61,392
----------------- ----------- ----------------- ---------------
As at 30 June 2018
Current - - 8,889 8,889
Non-current 52,495 - 8 52,503
----------------- ----------- ----------------- ---------------
52,495 - 8,897 61,392
----------------- ----------- ----------------- ---------------
Decommissioning and restoration of oil and gas assets
The provision outstanding at 30 June 2018 is expected to fall due
from 2032 onwards.
Litigation and Other Claims
Litigation and other claims consist of claims arising from trading
activities, were settled by 31 December 2017.
Other provisions
Amounts provided at 30 June 2018 comprise $8.9 million representing
the unavoidable net cost of exiting a contract.
Notes to the condensed interim financial statements (continued)
Year
As at As at ended
30 June 30 June 31 December
2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
17 Share capital
(a) Authorised
2,000,000,000 ordinary shares of 0.25p
each 7,963 7,963 7,963
(b) Called up, allotted and fully paid
746,019,407 ordinary shares of 0.25p
in issue at the beginning of the period
(30 June and 31 December 2017: 746,019,407) 3,061 3,061 3,061
Nil ordinary shares issued 0.25p each
during the period (30 June and 31 December
2017: Nil) - - -
746,019,407 ordinary shares of 0.25p
each (30 June and 31 December 2017:
746,019,407) 3,061 3,061 3,061
============= ============= =============
The balances classified as called up; allotted and fully paid
share capital represents the nominal value of the total number
of issued shares of the Company of 0.25p each.
Fully paid shares carry one vote per share and carry the right
to dividends.
Of the 746,019,407, 38,959,780 relates to treasury shares (30
June 2017: 39,778,765 31 December 2017: 39,710,823).
Notes to the condensed interim financial statements (Continued)
As at As at As at
30 June 30 June 31 December
2018 2017 2017
(Unaudited) (Unaudited) (Unaudited)
Percentage Percentage Percentage
Holding Holding Holding
18 Investments accounted for
using the equity method
Company
APICO LLC 27.18% 27.18% 27.18%
APICO (Khorat) Holdings LLC 27.18% 27.18% 27.18%
APICO (Khorat) Limited 27.18% 27.18% 27.18%
The investments in the jointly controlled entities have been classified
as joint ventures under IFRS 11 and therefore the equity method of
accounting has been used in the consolidated financial statements.
The table below shows the movement in investments in the jointly controlled
entities:
As at As at Year ended
30 June 30 June 31 December
2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
Balance at the beginning of
the period 120,964 130,736 130,736
Share of profit of investments 1,818 2,560 4,181
Impairment - - (7,800)
Dividends received (951) (3,126) (6,523)
Additions 1,614 218 370
============== ============= =============
123,445 130,388 120,964
============== ============= =============
As at As at Year ended
30 June 30 June 31 December
2018 2017
(Unaudited) (Unaudited) 2017
$'000 $'000 $'000
19 Reserves
Treasury shares (149) (153) (152)
Other reserves (note 20) 1,084,307 1,487,955 1,458,680
------------- ------------- -------------
1,084,158 1,487,802 1,458,528
Non-controlling interest (1) - (280) (280)
------------- ------------- -------------
1,084,158 1,487,522 1,458,248
============= ============= =============
(1) The non-controlling interest relates to Dominion Uganda Limited, where the Group acquired a 95% shareholding during 2012. The entity was dissolved in the first half of 2018.
Foreign
(7) currency
translation
reserve
$'000 Accumulated Total
Merger Equity Cash flow
Share Capital Options (5) reserve (6) component (8) hedges
premium redemption premium Consolidation on convertible profits
(1) (2) reserve (3) reserve (4) reserve bond / (losses) other reserves
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
================= ============ ================ ============ ======================== ============== ====================== ================== ========================= =================== ==================
20 Other
reserves
As at 1 January
2017 807,427 160 57,794 (500) 667,337 669 5,569 - 33,993 1,572,449
Loss for the
period,
net of tax - - - - - - - - (84,618) (84,618)
Other
comprehensive
loss, net of tax - - - - - - - - - -
============ ================ ============ ======================== ============== ====================== ================== ========================= =================== ==================
Total
comprehensive
loss, net of
tax - - - - - - - - (84,618) (84,618)
Share-based
payments - - 124 - - - - - - 124
============ ================ ============ ======================== ============== ====================== ================== ========================= =================== ==================
As at 30 June
2017
(Unaudited) 807,427 160 57,918 (500) 667,337 669 5,569 - (50,625) 1,487,955
Loss for the
period,
net of tax - - - - - - - - (27,174) (27,174)
Other
comprehensive
income, net of
tax - - - - - - - (5,882) - (5,882)
============ ================ ============ ======================== ============== ====================== ================== ========================= =================== ==================
Total
comprehensive
loss, net of
tax - - - - - - - (5,882) (27,174) (33,056)
Share-based
payments - - 3,781 - - - - - - 3,781
Transfers within
reserves - - - - (341,792) - - - 341,792 -
------------ ---------------- ------------ ------------------------ -------------- ---------------------- ------------------ ------------------------- ------------------- ------------------
As at 31
December
2017 807,427 160 61,699 (500) 325,545 669 5,569 (5,882) 263,993 1,458,680
------------ ---------------- ------------ ------------------------ -------------- ---------------------- ------------------ ------------------------- ------------------- ------------------
Adjustment on
adoption
of IFRS 9 - - - - - - - 2,300 (2,300) -
------------ ---------------- ------------ ------------------------ -------------- ---------------------- ------------------ ------------------------- ------------------- ------------------
As at 1 January
2018 807,427 160 61,699 (500) 325,545 669 5,569 (3,582) 261,693 1,458,680
Loss for the
period,
net of tax - - - - - - - - (375,408) (375,408)
Other reserves
(continued)
Foreign
(7) currency
translation
reserve
$'000 Accumulated Total
Merger Equity Cash flow
Share Capital Options (5) reserve (6) component (8) hedges
premium redemption premium Consolidation on convertible profits
(1) (2) reserve (3) reserve (4) reserve bond / (losses) other reserves
$'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000 $'000
Other
Comprehensive
loss, net of
tax - - - - - - (31) (727) - (758)
Total
comprehensive
loss, net of
tax - - - - - - (31) (727) (375,408) (376,166)
Disposal of
Non-Controlling
Interest - - - - - - - - (280) (280)
Share-based
payments - - 2,073 - - - - - - 2,073
Transfers within
reserves (7,868) 7,868 -
As at 30 June
2017
(Unaudited) 807,427 160 55,904 (500) 325,545 669 5,538 (4,309) (106,127) 1,084,307
============ ================ ============ ======================== ============== ====================== ================== ========================= =================== ==================
(1) The share premium account represents the total net proceeds on issue of the Company's shares in excess of their nominal value of 0.25p per share less amounts transferred to any other reserves.
(2) The capital redemption reserve represents the nominal value of shares transferred following the Company's purchase of them.
(3) The option premium reserve represents the cost of share-based payments to Directors, employees and third parties.
(4) The consolidation reserve represents a premium on acquisition of a minority interest in a controlled entity.
(5) In 2017, the premium arising on the 2012 Dominion Petroleum acquisition, which was classified within the merger reserves according to the provisions of the Companies Act 2006 relating to Merger Relief (s612 and s613), was realised to accumulated profits/(losses)as a result of the full impairment of the Dominion Group in previous years.
(6) This balance represents the equity component of the convertible bond, net of costs and tax as a result of the separation of the instrument into its debt and equity components. The bond was converted into 21,661,476 ordinary shares of 0.25p each on 21 May 2008.
(7) The foreign currency translation reserve is used to record unrealised exchange differences arising from the translation of the financial statements of entities within the Group that have a functional currency other than US Dollars.
(8) The cash flow hedge reserve records the portion of the gain or loss on a hedging instrument in a cash flow hedge that is determined to be an effective hedge. It includes $4.3 million relating to commodity price hedges which will be reclassified to the income statement as the forecast sales occur.
21 Capital commitments
In acquiring its oil and gas interests, the Group has pledged
that various work programmes will be undertaken on each permit/interest.
The exploration commitments in the following table are an estimate
of the net cost to the Group of performing these work programmes:
year ended
as at As at
30 June 30 June 31 december
2018 2017 2017
(Unaudited) (Unaudited) (Unaudited)
$'000 $'000 $'000
Due within one (1) year 15,455 37,502 4,830
Due later than one (1) year
but
within two (2) years 1,180 31,340 26,940
Due later than two (2) years
but
within five (5) years 35,440 545 90
----------------- ------------- --------------
52,075 69,387 31,680
----------------- ------------- --------------
22 Contingent liabilities
An individual's claim against the Group relating to the evaluation and subsequent disposal of an interest that was held in exploration blocks within the portfolio is still ongoing. The individual's primary claim was dismissed in February 2018. The individual has filed an appeal against the decision but a loss at first instance supports the Group's view that the claims are without merit and accordingly the Group has estimated that no liability will arise as a result of proceedings and therefore no provision for any liability has been made in these financial statements.
23 Events after the reporting period
On 6 September 2018, Ophir completed the acquisition of a package of Southeast Asian assets from Santos. Ophir acquired interests in three producing assets: (i) a 31.875% working interest in the Block 12W PSC in Vietnam; (ii) a 45% operated interest in the Sampang PSC in Indonesia; and (iii) a 67.5% operated interest in the Madura Offshore PSC in Indonesia for a total consideration of $144 million. The acquisition of the assets was structured so as to have an effective date of 1 January 2018, with cash flows generated by the assets post the effective date (but pre-completion) netted off against the original purchase price of $205 million. The cash flows generated by the assets in 2018 have been better than Ophir's expectations, owing to higher than expected commodity prices over the period and production from the Chim Sáo field in Vietnam outperforming. The total consideration is therefore $144 million. The transaction will be accounted for in accordance with IFRS 3 business combinations. Due to the close proximity of the acquisition date to the date of these financial statements, the initial accounting for the business combination is incomplete and the group is unable to provide a quantification for the fair value of the acquired assets and liabilities. The fair value exercise is ongoing and the group will include the acquisition balance sheet in its full-year results for 2018. The transaction was funded partly from an eighteen month bridge facility of up to $130 million, with the balance being met from existing funds. The bridge facility was executed on 7 June 2018 with a number of our existing lenders. With the reduced consideration payable to Santos, $103 million of the bridge was drawn--down. The acquisition of the Santos assets is intended to take the group closer to achieving its goal of becoming a stable, self-financing E&P company.
Company Information
Registered Office and Head Office
Fourth Floor
123 Victoria Street
London SW1E 6DE
Telephone: +44 (0)20 7811 2400
Website: www.ophir-energy.com
Directors
Chairman (Non-Executive) Independent Non-Executive Directors
William (Bill) Schrader Ronald Blakely (resigned 31 March
2017)
Executive Directors Dr Carol Bell
Vivien Gibney
Dr Nicholas (Nick) Cooper - Chief David Davies
Executive Officer (resigned 18 Dr Carl Trowell
May 2018)
Dr William (Bill) Higgs - Chief
Operating Officer (resigned 7 August
2017)
Anthony (Tony) Rouse - Chief Financial
Officer
Alan Booth - Interim Chief Executive
Officer
Company Secretary
Philip Laing
Registrars
The Company has appointed Equiniti Limited to maintain its register of members. Shareholders should contact Equiniti using the details below in relation to all general enquiries concerning their shareholding:
Equiniti Limited*
Aspect House
Spencer Road
Lancing, West Sussex BN99 6DA
Telephone: 0871 384 2030**
International dialling: +44 121 415 7047
* Equiniti Limited and Equiniti Financial Services Limited are part of the Equiniti group of companies. Company share registration, employee scheme and pension administration services are provided through Equiniti Limited, which is registered in England & Wales with No. 6226088. Investment and general insurance services are provided through Equiniti Financial Services Limited, which is registered in England & Wales with No. 6208699 and is authorised and regulated by the UK Financial Conduct Authority.
** Lines are open Monday - Friday from 9.00am - 5.30pm (UK time), excluding UK bank holidays.
Auditors: Solicitors:
Ernst & Young LLP Linklaters
One More London Place One Silk Street
London SE1 2AF London EC2Y 8HQ
United Kingdom United Kingdom
Bankers: Corporate Brokers:
HSBC Bank plc Bank of America Merrill Lynch
70 Pall Mall 2 King Edward Street
London SW1 5EY London EC1A 1HQ
United Kingdom United Kingdom
Financial PR Advisors: Morgan Stanley
Brunswick Group LLP 20 Bank Street
16 Lincoln's Inn Fields Canary Wharf
London WC2A 3ED London E14 4AD
United Kingdom United Kingdom
-------------------------------
This information is provided by RNS, the news service of the London Stock Exchange. RNS is approved by the Financial Conduct Authority to act as a Primary Information Provider in the United Kingdom. Terms and conditions relating to the use and distribution of this information may apply. For further information, please contact rns@lseg.com or visit www.rns.com.
END
IR SFMFAEFASEIU
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September 13, 2018 02:01 ET (06:01 GMT)
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