Source - RNS
RNS Number : 8826J
Ophir Energy Plc
15 September 2016
 



15 September 2016

OPHIR ENERGY PLC

Half Year Results for the six months ended 30 June 2016

Commenting on the first half results, Nick Cooper, Chief Executive, Ophir Energy said:

"Ophir's strategy is to be a sustainable explorer, focussed on delivering NAV per share growth by finding (securing) resources at low cost and then monetising them in the way that maximises the price achieved.

Ophir's financial strength and the discretionary nature of the capital spend across our portfolio provides Ophir with optionality to selectively invest in organic, and inorganic, opportunities that offer the best project returns and therefore the greatest growth in NAV per share.

Having spent two years high-grading our exploration portfolio, we are now preparing to return to a considered, prudent pace of exploration drilling from late 2016 to take advantage of the significantly lower exploration costs, while continuing to focus on monetising our previous exploration successes.

 

In Equatorial Guinea, Fortuna is now a low cost upstream project, "technically ready" for FID and we are constructing a value chain that offers potentially the most cost-effective greenfield LNG supply available today. Ophir will progress the monetisation of Fortuna in a way that protects Ophir's balance sheet, that actively manages our exposure to development risk, and that maximises NAV per share.

 

Ophir's cash flow and net cash position provide sufficient funding to make discretionary investments across the portfolio. Our cost rationalisation programmes have delivered substantial savings in 'running costs' and these efforts continue, thereby minimising NAV per share erosion and maximising shareholder returns."

 

Financial

·    Revenue of $52 million (1H 2015: $86 million) with a further $6m (1H 2015: $5m) for Sinphuhorm accounted for using the equity method

·    Pre-tax loss of $70 million (1H 2015: $123 million)

·    Post tax cash generated from production of $22 million1 (1H 2015: $37 million)

·    Cash on balance sheet at period end of $407 million (1H 2015: $708 million, including short-term cash deposits)

·    Net cash on balance sheet of $207 million (1H 2015: $392 million)

Monetisation of Resource

·    Average daily production of 11,000 boepd (including Sinphuhorm),  in line with expectations

·    Completed a water debottlenecking and facilities upgrade at Bualuang in September, resulting in increased water handling capacity of 75,000 bwpd and a 25% increase in oil of 2,000 bopd from initial rates

·    Delivered first gas from the Kerendan field, Indonesia to the PLN power plant in August 2016

·    Completed upstream FEED on Fortuna FLNG project and locked in low cost solutions until mid-2017. Discussions with potential value chain partners continue.

·    Achieved zero LTIs in 1H 2016 and two years' LTI-free operations in Thailand

Exploration and Appraisal

·    High-graded exploration portfolio :

Exited several licenses and entered Block CI-513 in Cote D'Ivoire, Ayame prospect (c. 240 MMbo of gross mean prospective resource) expected to be drilled in mid-2017

Matured an inventory of exploration prospects in Block AD-03, Myanmar to drill-ready status

Progressed an oil play in Block R, Equatorial Guinea jointly with Exxon with drill/drop decision to be made in 2017

·    Mapped multiple leads and prospects with multi-hundred million barrel potential on the Olumi Rouge 3D in (Nkouere & Nkawa Blocks) Gabon

·    Commenced Trepang 3D seismic survey in West Papua/Aru licences in Indonesia in August

·    Mobilised for the acquisition of the Kerendan 3D seismic survey in September

 

A presentation for analysts will be held at 9.30am following this announcement. This will be webcast live through the link on the Company website: www.ophir-energy.com/investors.   

 

Ends

 

For further enquiries please contact:

 

Ophir Energy plc

+44 (0)20 7811 2400

Nick Cooper, CEO

Tony Rouse, CFO

Geoff Callow, Head of Investor Relations and Corporate Communications



Brunswick Group

+44 (0)20 7404 5959

Patrick Handley

Wendel Verbeek



BUSINESS REVIEW

Health, Safety, Security and Environment

The Board of Ophir is committed to robust health, safety, security and environmental management. During the first half of 2016, over 750,000 man hours were worked with no recordable lost time incidents. In May 2016 we completed two years of lost time incident free operations in Thailand; and early in the second half of 2016, we achieved five years of incident free production operations on our Thai operated assets. Both of these are significant achievements, of which everyone involved with our operations is proud.

Sources and Uses of Funds Summary


Units

1H 2016

1H 2015

FY 2015

Net Sources of Funds:





Revenue

$'millions

52.1

86.5

161.1

Cost of production1

$'millions

(30.1)

(49.5)

(72.5)

Total net sources of funds from production

$ 'millions

22.0

37.0

88.6

Net Uses of Funds:





Capital Expenditure (including pre-licence expenditure)

$'millions

96.4

105.4

208.8

Net administration cost

$'millions

9.3

19.4

31.3

Net interest cost

$'millions

7.5

7.3

17.0

Total net uses of funds

$'millions

113.2

132.1

257.1

Financing:





Closing net cash

$'millions

206.9

392.0

354.9

Closing debt

$'millions

200.3

316.2

259.7

Closing cash and cash equivalents

$'millions

407.2

708.2

614.6

1 This consists of operating expenses, royalty payments, current taxation and movement in inventories of oil.

 

Net Sources of Funds

In the first half of 2016, Ophir's working interest production averaged 11,000 boepd and is on schedule to be in line with full year guidance of 10,500 - 11,500 boepd. This production comprised 9,000 bopd from Bualuang and 2,000 boepd from Sinphuhorm.

The lower commodity price environment of 2015 continued during the early months of 2016, with Brent prices falling to a low of ca. $27.00/bbl, before recovering towards $50.00/bbl in June. Against this environment, revenue from the Bualuang asset totalled $52 million or $34.17/bbl (1H 2015: $86 million or $60.48/bbl). Given the robust nature of the Bualuang asset to deliver cash flow in a low commodity price environment, underlying cash flow from Bualuang production (after operating costs and taxation) totalled $22 million or $13.57/bbl (1H 2015: $37 million or $18.08/bbl).

At the Kerendan asset, an amendment to the GSA was signed, setting the contract commencement date at 11 January 2016. The Group has therefore recognised $8.2 million on the balance sheet as deferred income for PLN's take or pay obligation in respect of the period since this date.

With the increased commodity price outlook, the Group's underlying post tax cash flow from production for the full year 2016 is forecast to deliver between $50 million and $70 million or $15/bbl to $23/bbl. Longer-term, underlying cash flow from production for the period 2016-18 is expected to deliver approximately $200 million at current forward curve oil price assumptions. In comparison, Ophir has a total committed capital expenditure of only $93 million over the same period. Together these factors ensure that Ophir has the financial capacity to invest in selected, discretionary additional activities that have the potential to generate attractive risk-weighted returns for shareholders.

Uses of Funds

The Group's primary investments during 1H 2016 comprised:

·     Exploration (total $38 million) comprising predominantly:

Acquisition of Cote D'Ivoire block CI-513 ($18 million)

Myanmar AD-03 - Well planning and Environmental Impact Assessment ($5 million)

Acquisition of Malaysia block 2A ($6 million)

·     Monetisation of resource ($42 million) comprising:

Tanzania Blocks 1&4 - Pre-development spend ($7 million)

Equatorial Guinea Fortuna - Front End Engineering Design ($31 million)

Thailand Bualuang - Water debottlenecking project ($4 million)

 

In the period the Group charged to the income statement exploration expenses of $69 million (1H 2015: $95 million). These were predominantly driven by the $57 million write off incurred due to the decision taken to exit the G4/50 licence in the Gulf of Thailand in the second half of 2016.

The Group has lowered its capital expenditure forecast for the year to between $140 million and $170 million (from $150 million to $200 million), reflecting its lower activity plans in response to the continued low commodity price. Looking forward, the Group's expenditure plans in 2H 2016 comprise:

·     Thailand - completion of the Bualuang water debottlenecking project $11 million

·     Indonesia - seismic data on the West Papua and Aru blocks  $11 million

·     Tanzania - 2 well programme on Blocks 1 and 4 operated by Shell $20 million

 

Since the start of 2015, Ophir has embarked on several phases of cost reductions. In total these have reduced the Group's gross administration cost base (including manpower) by ca. 52%. This is also reflected in the Group reporting lower net administration expenses in the period of $9 million compared to $19 million in the same period last year, a reduction of 53%.

Financing

The Group incurred net interest charges of $7.5 million (1H 2015: $7.3 million). In the context of its overall net cash position, the Group has decided to defer a refinancing of its debt facilities, to partially de-lever and reduce its interest charges and to wait for more favourable market conditions. The Group therefore reduced its total debt outstanding and its leverage by repaying $59 million of its reserves based lending facility at the end of June. The Group's debt outstanding at the period-end is comprised of a reserves based lending facility of $94 million (1H 2015: $210 million) and high yield Nordic bond of $107 million (1H 2015: $107 million).

The Group's balance sheet remains robust with closing net cash of $207 million (1H 2015: $392 million), and $407 million of cash (1H 2015: $708 million, including short-term cash deposits).

The Group forecasts that net cash at the year-end will be $175 million to $225 million and it will hold cash balances of approximately $400 million to $450 million, assuming no refinance prior to the end of the year.

Resource and Reserves Monetisation

Ophir's strategy allows it to monetise resources and reserves in whichever way maximises NAV per share. Specifically monetisation can be through producing barrels, through developing barrels or through selling barrels on discovery. As the Group is not strategically tied to reserves or production growth targets, it can select whichever is most appropriate for each asset to create value. In the Group's history it has demonstrated its ability to execute on all three monetisation routes.  

Reliable, diversified cash flow from our production base is an important part of our strategy to become a self-sustaining explorer. We have invested in our production base where there is an opportunity to enhance operating cash flow per boe at attractive returns.  

Ophir will only proceed with development projects that offer demonstrable value creation for equity holders without undermining the Group's funding position or its exploration led strategy.  For certain assets this means that we look to partially or wholly monetise on discovery.

Bualuang, Thailand

During the first half we completed phase 1 of the water debottlenecking project on the Bualuang field, which increased the water disposal capacity from c. 44,000 to greater than 75,000 bwpd. The second phase of this debottlenecking project has recently been successfully completed in September. As a result of these actions, the water handling capacity of the field increased from 50,000 bwpd to 75,000 bwpd. This increase in water handling capability has thus far resulted in a 2,000 bopd increase in oil production since the new facilities were fully commissioned. The economic benefit will be extended through the next phase of Bualuang development, as no additional processing facilities will be required, both simplifying the design and materially reducing capital expenditure.  

The two phases of the water debottlenecking project cost a total of $21 million and is expected to increase the NPV10 of the field by $83 million with payback in approximately 12-18 months.

Separately, the Group has processed and interpreted the Bualuang platform undershoot 3D seismic data. This has improved the fidelity of the imaging of the asset and will be important for guiding future phases of development and infill exploration drilling. The 3D seismic results indicate the potential for future increases to 2P reserves, 2C resources and have identified additional prospective resources. Looking forward, the Group is commencing plans for infill drilling in 2017 to confirm and to monetise these reserves and resources. These plans are expected to include a further phase of drilling and of development for the Bualuang asset.

Fortuna, Equatorial Guinea

Ophir's pre-development portfolio primarily comprises of the 900 MMboe of contingent resource in Tanzania and Equatorial Guinea that we have discovered and are seeking to monetise in Tanzania and Equatorial Guinea.

The Fortuna FLNG project in Equatorial Guinea is a prime example of this approach. We have made significant progress in maturing the project and value chain to the point where it is technically ready to FID. The upstream portion of the value chain is technically ready to FID and the downstream, offtake portion is ready for a final Group decision between the competing offtake offers.  

We have shortlisted four high quality, high credit-rated gas off-takers, all of whom are significant players in the LNG market. Our innovative approach to the upstream FEED (Front End Engineering and Design) has resulted in two world class consortia bidding for the Upstream EPCIC (Engineer, Procure, Construct, Install & Commission) contract. As a result we have reduced estimated upstream costs from ca. $1 billion at the end of 2014 to ca. $450 million today. On a point forward basis, these represent an upstream development cost of ca. $1.70/boe.

Regarding the midstream portion of the value chain, Ophir and Golar LNG continue to explore ways to work together to monetise the discovered resource in the Fortuna field.  Discussions are progressing well and both parties are working towards an FID decision being made before the end of 2016.

The value chain, and our understanding of costs along this value chain, are sufficiently mature that we estimate that Fortuna is the lowest cost greenfield LNG project in the market today. As such the Fortuna Project continues to offer compelling returns despite the low commodity price environment.

Block 1&4, Tanzania

In Tanzania, Shell took over the operatorship from BG Group in February 2016 and has since undertaken a review of the project plan, the development scope and the cost stack of the project. Interaction with Shell has demonstrated their appetite to progress this asset and the imminent drilling of two exploration wells on Blocks 1 and 4 are evidence of this.

Separately, since the late 2015 elections in Tanzania, the new President has taken a more pro-active, hands-on approach to delivering the project. We have experienced an increased Government focus on key items to enable the development and there is now a political impetus to accelerate the project. This was confirmed by the award of the land for the location of the midstream facilities. The Group will continue to determine the optimum way to monetise this asset for and to deliver value for shareholders.

Kerendan, Indonesia

The upstream elements of the Kerendan field development in Indonesia were completed in late 2015. Activity in the first half of 2016 centred around supplying commissioning gas to the offtaker, PLN, at the power plant. The first phase of the transmission network from the power plant to Buntok is complete. This has enabled to the start-up of production at initial rates of ca. 5 MMscfd, as announced on 13th September 2016. The last phase of the transmission line to Tanjung, where it will link to the East Kalimantan grid, is due for completion before year-end. Once complete, production will ramp up to the full daily contract quantity of 20 MMscfd.

The contractual start date for production was 11 January 2016; a take or pay provision has therefore been active since this date. As part of the contract, the inflation mechanism was adjusted from 3% every three years to 3% per annum.

Discussions regarding an upward revision to the contracted gas price are at an advanced stage and are expected to conclude before the end of the year. 

Exploration

Monetising exploration success is the means by which Ophir delivers for shareholders.

The Group has been high-grading the exploration portfolio over the past 24 months; a process that has seen us exit 5 licences and enter 5 licences with low commitment costs and attractive economics. The high-grading process involves both technical and commercial screening. The Group will only pursue the plays that have the potential to create material value on a risk weighted basis at a prevailing oil price of below $50 per barrel.  Furthermore, to maintain our balance sheet strength and spread our portfolio risk appropriately, we will only commit to drilling wells at the appropriate equity interest to reflect the risk reward opportunity of the prospect.

The Group is ready to recommence its drilling programme and we currently envisage drilling between three and five operated wells in the 2017-2018 period. In addition, we will be participating in two non-operated exploration wells in Tanzania with Shell in late 2016.

During the first half of 2016 we entered Cote D'Ivoire, signing a PSC for Block CI-513, which Ophir operates with a 45% interest. This is a block that satisfied our technical criteria some two years ago, but which we only entered in 2016 after agreeing fiscal terms with the government of Cote D'Ivoire that allowed the block to meet our commercial threshold. We have high graded the Ayame prospect, which is liquids-prone with mean prospective recoverable resources of ca. 240 MMbo and a 27% chance of success. With drilling costs at, or near to, cyclical lows the expected reduced well cost is ca. $15m-18m net to Ophir.

Elsewhere in the portfolio, the past two years have enabled the Group to reflect on lessons learnt, to assimilate new data acquired by the industry and by itself, and to materially advance out its play understandings. Following seismic data acquisition in 2015, interpretation of these datasets has identified numerous leads and prospects in Myanmar, West Papua and Gabon. A growing number of these prospects have cleared commercial and technical thresholds and are now options for our operated exploration drilling programme in 2017-18.

In Equatorial Guinea, the southwest portion of Block R contains a potential extension of an oil play in the neighbouring block. Exxon, the operator of the adjoining block completed a 3D seismic survey earlier this year and we granted them permission to extend the survey into our acreage. We are now waiting to receive the data before deciding how to proceed on this play. Looking at analogues in the Niger Delta there is the potential for this data to reveal prospects in the hundred of millions of barrels range.

In Indonesia, we completed preparations for the offshore Trepang 3D seismic survey on the West Papua/Aru licences and the 3D data acquisition commenced in August 2016.  We also completed the reprocessing of existing seismic over the West Aru licence which has enabled us to mature a number of leads to prospects. As we process and interpret the new data we expect both areas to contribute further drilling candidates for 2017/18.

During the first half, we took the decision not to proceed with further exploration drilling in the G4/50 licence in the Gulf of Thailand. Whilst the drilling campaign in the second half of 2015 had proven the presence of a working hydrocarbon system in a previously undrilled part of the basis, the opportunity did not offer compelling risk adjusted returns and therefore we decided to maintain capital discipline and let the licence lapse. Expenditure relating to this license has therefore been written off in the first half of 2016.

A non-operated exploration drilling programme will commence in 4Q 2016 with the commencement of a two well programme in Tanzania operated by Shell. This will consist of one well in Block 1 and one well in Block 4. These wells are targeting resource that is close to the planned location of sub-sea development infrastructure and can be tied back easily thus improving the economics of any potential development.

New Ventures

We continue to seek new opportunities to build out our portfolio within our preferred play fairways that screen well against our technical and commercial thresholds. As an example, we recently submitted a Joint Study Agreement covering the open acreage adjacent to our licences in West Papua with our partner Statoil. We expect to make further progress in capturing more acreage in the second half of the year that will potentially add to the prospect inventory and provide short and medium term drilling opportunities.

Additionally, we continue to cautiously evaluate opportunities outside our core areas where we can access world class acreage in new provinces on attractive terms.

Risk Management

The Group's Executive Directors constantly monitor the group's risk exposures and report to the Audit, Corporate Responsibility and Technical Advisory Committees on a six monthly basis. Risks that have the potential to have a high impact on the Company are each reviewed, together with the controls the Company has put in place, with the Board on at least an annual cycle. The Audit Committee provides oversight on risk whilst ultimate authority for risk management remains with the Group's Board. The Corporate Responsibility Committee provides oversight on surface risk, particularly in the areas of Health, Safety and the Environment. The Technical Advisory Committee provides oversight on subsurface risk and uncertainty for exploration and development activities.

The principal risks for the Group remain as previously detailed on pages 16 to 19 of the 2015 Annual Report and Accounts. The principal risks can be summarised as follows:

·    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.

·    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.

 

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

 

 

 

Nick Cooper

               

 

                                 

 

 

Chief Executive Officer                                                                

 

 



 

 

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 2016 which comprises the 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 related notes 1 to 24. 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 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 Ireland) 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 2016 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Conduct Authority.

 

 

Ernst & Young LLP

London

14 September 2016

 

 

 

Condensed consolidated income statement and statement of comprehensive income
Six months ended 30 June 2016

 

Notes


6 Months Ended

30 June 2016

(Unaudited)

$'000


6 Months ended

30 June 2015

(Unaudited)

$'000


 

Year ended

31 December 2015

$'000

Consolidated income statement

Continuing operations







 

 









Revenue

4


52,097


86,495


161,090

Cost of sales

5a


(54,676)


(64,499)


(128,816)

Gross (loss)/profit



(2,579)


21,996


32,274









Gain on farm-out

5b


-


245


245

Share of profit of investments accounted for using the equity method

19


2,818


4,066


7,219

Impairment of oil and gas properties



-


-


(126,732)

Impairment of equity accounted investments



-


-


(42,117)

Exploration expenses

5c


(68,731)


(94,867)


(183,137)

General & administration expenses

5d


(9,332)


(19,440)


(31,252)

Other operating income/(expenses)

5e


8,580


(23,039)


(25,258)

Operating loss



(69,244)


(111,039)


(368,758)









Net finance expense

6


(380)


(6,889)


(10,662)

Other financial (losses)/gains

7


-


(5,367)


3,372

Loss from continuing operations before taxation



(69,624)


(123,295)


(376,048)









Taxation benefit/(expense)

8


21,177


(7,717)


53,596

Loss from continuing operations for the period attributable to:



(48,447)


(131,012)


(322,452)









Equity holders of the Company



(48,447)


(131,012)


(322,452)

Non-controlling interest



-


-


-




(48,447)


(131,012)


(322,452)

Earnings per share 








Basic - Loss for the period attributable to equity holders of the Company



(6.9) cents


(20.0) cents


(47.1) cents

Diluted - Loss for the period attributable to equity holders of the Company


                      

(6.9) cents


 (19.8) cents


(47.1) cents









 

Condensed consolidated income statement and statement of comprehensive income
Six months ended 30 June 2016 (continued)

Notes


6 Months Ended

30 June 2016

(Unaudited)

$'000


6 Months ended

30 June 2015

(Unaudited)

$'000


 

Year ended

31 December 2015

$'000

Consolidated statement of comprehensive income







Loss from continuing operations for the period


(48,447)


(131,012)


(322,452)

 

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


(1,049)


(702)

Other comprehensive income/(loss) for the period, net of tax


31


(1,049)


(702)









Total comprehensive loss for the period, net of tax attributable to:







Equity holders of the Company



(48,416)


(132,061)


(323,154)

Non-controlling interest



-


-


-




(48,416)


(132,061)


(323,154)

 

 

Condensed consolidated statement of financial position

As at 30 June 2016

 

Notes


As at

30 June 2016

(unaudited)

$'000


As at

30 June 2015

(unaudited)

$'000


As at

31 December

2015

$'000









Non-current assets








Exploration and evaluation assets

9


892,261


895,904


879,914

Oil and gas properties

10


643,307


793,074


662,177

Other property, plant and equipment



4,724


6,131


5,140

Financial assets



25,970


59,910


27,253

Investments accounted for using the equity method

19


133,786


173,920


130,200




1,700,048


1,928,939


1,704,684

Current assets








Inventory

11


58,158


45,896


50,216

Trade and other receivables



44,024


53,830


32,071

Taxation receivable



22,322


13,202


22,322

Cash and cash equivalents

12


407,226


608,207


614,569

Investments

13


-


100,000


-




531,730


821,135


719,178

Total assets



2,231,778


2,750,074


2,423,862









Current liabilities








Trade and other payables

14


(100,149)


(131,879)


(115,971)

Interest-bearing bank borrowings due within one year

15


(5,389)


(53,332)


(37,059)

Taxation payable



(11,779)


(49,769)


(38,056)

Provisions

17


(36,350)


(49,142)


(47,737)




(153,667)


(284,122)


(238,823)

Non-current liabilities








Interest-bearing bank borrowings

15


(88,267)


(156,498)


(115,949)

Bonds payable

16


(106,650)


(106,371)


(106,651)

Deferred tax liability

8d


(214,874)


(301,058)


(245,745)

Provisions

17


(68,594)


(64,597)


(67,190)




(478,385)


(628,524)


(535,535)

Total liabilities



(632,052)


(912,646)


(774,358)

Net assets



1,599,726


1,837,428


1,649,504









 

 

Condensed consolidated statement of financial position

As at 30 June 2016 (continued)

 

Notes


As at

30 June 2016

(unaudited)

$'000


As at

30 June 2015

(unaudited)

$'000


As at

31 December

2015

$'000

 

Capital and reserves








Called up share capital

18


3,061


3,061


3,061

Reserves

20


1,596,945


1,834,647


1,646,723

Equity attributable to equity shareholders of the Company



1,600,006


1,837,708


1,649,784

Non-controlling interest



(280)


(280)


(280)

Total equity



1,599,726


1,837,428


1,649,504

 

Approved by the Board on 14th September 2016

 

 

 

 

Nick Cooper                                                                        Tony Rouse

Chief Executive Officer                                                      Chief Financial Officer                            


Condensed consolidated statement of changes in equity

Six months ended 30 June 2016

 

Called up share  capital
$'000

Treasury shares
$'000

Other        reserves 1 
$'000

 

 

Non-controlling interest
$'000

Total equity
$'000







As at 1 January 2015

2,474

(59)

1,695,904

(280)

1,698,039







Loss for the period, net of tax

-

-

(131,012)

-

(131,012)

Other comprehensive income, net of tax

-

-

(1,049)

-

(1,049)

Total comprehensive loss, net of tax

-

-

(132,061)

-

(132,061)

New ordinary shares issued to third parties

587

-

325,545

-

326,132

Purchase of own shares

-

(99)

(56,011)

-

(56,110)

Exercise of options

-

1

-

-

1

Share-based payment

-

-

1,427

-

1,427







As at 30 June 2015 (Unaudited)

3,061

(157)

1,834,804

(280)

1,837,428







Loss for the period, net of tax

-

-

(191,440)

-

(191,440)

Other comprehensive income, net of tax

-

-

347

-

347

Total comprehensive loss, net of tax

-

-

(191,093)

-

(191,093)

Exercise of options

-

2

-

-

2

Share-based payment

-

-

3,167

-

3,167







As at 1 January 2016

3,061

(155)

1,646,878

(280)

1,649,504

 






Loss for the period, net of tax

-

-

(48,447)

-

(48,447)

Other comprehensive income, net of tax

-

-

31

-

31

Total comprehensive loss, net of tax

-

-

(48,416)

-

(48,416)

Exercise of options

-

2

-

-

2

Share-based payment

-

-

(1,364)

-

(1,364)







As at 30 June 2016 (Unaudited)

3,061

(153)

1,597,098

(280)

1,599,726

 

1 Refer to note 21 - Other reserves

 






 

Condensed consolidated statement of cash flows
Six months ended 30 June 2016

 

Notes

6 Months Ended

30 June 2016

(unaudited)

$'000

6 Months ended

30 June 2015

(unaudited)

$'000

Year ended

31 December 2015

$'000

 






 

Operating activities





 

Loss before taxation


(69,624)

(123,295)

(376,048)

 

Adjustments to reconcile loss before taxation to net cash provided by operating activities





 

Exploration expenditure written off

5c

60,069

94,867

183,137

 

Depreciation and amortisation

5

35,578

48,559

85,127

 

Impairment and loss/(gain) on disposal of fixed assets


14

(100)

169,307

 

Share of profits from joint ventures

19

(2,818)

(4,066)

(7,219)

 

Net charge for interest

6

7,486

11,770

30,394

 

Net foreign currency losses/(gains)

6

1,513

486

(6,014)

 

Share-based payment (release)/expense

5d

(1,364)

1,427

4,594

 

Cash flow from operation before working capital adjustments


30,854

29,648

83,278

 

Increase in inventories


(7,943)

(1,770)

(7,172)

 

(Decrease)/increase in other current and non-current payables


(3,477)

18,739

20,635

 

(Increase)/decrease in other current and non-current assets


(10,665)

22,783

25,343

 

Interest received


1,044

1,496

2,051

 

Income taxes paid


(35,972)

(78,012)

(83,042)

Net cash (used in)/generated by operating activities


(26,159)

(7,116)

41,093

Investing activities





Proceeds from farm-out


-

2,100

2,100

Additions to intangibles and property, plant and equipment


(112,449)

(253,028)

(355,908)

Purchase of exploration licences, net of cash acquired


-

-

(18,965)

Dividends received from joint ventures  


408

1,087

5,843

Funding provided to joint ventures


(1,176)

(3,941)

(3,941)

Decrease in other financial assets


-

196,630

331,484

Net cash used in investing activities

(113,217)

(57,152)

(39,387)

Financing activities





Interest paid


(8,530)

(11,190)

(22,521)

Repayment of debt

(59,352)

(183,740)

(240,521)

Net issue/(repurchase) of shares


2

(56,107)

(56,106)

Cash acquired on acquisition of subsidiary


-

48,827

48,827

Net cash used in financing activities

(67,880)

(202,210)

(270,321)

Currency  translation differences relating to cash and cash equivalents

(87)

(3,187)

5,312

Decrease in cash and cash equivalents

(207,343)

(269,665)

(263,303)

Cash and cash equivalents at beginning of period

614,569

877,872

877,872

Cash and cash equivalents at end of period

407,226

608,207

614,569

 


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 and deepwater 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 Changes in Equity, Statement of Financial Position, Statement of Cash Flows and associated Notes to the Financial Statements for the financial year ended 31 December 2015 included in the 30 June 2016 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 2015 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 12. These condensed consolidated interim financial statements of the Group for the six months ended 30 June 2016 were approved and authorised for issue by the Board of the Directors on 14 September 2016.   

 

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 2016 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.

 

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 2015 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 2015. 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 2015, except for the adoption of the following standards and amendments:

 

New and amended accounting standards and interpretations

 

The Group has adopted the following relevant new and amended IFRS and IFRIC interpretations as of 1 January 2016:

 

·    Amendments to IFRS 10, IFRS 12 and IAS 28 'Investment Entities - Applying the Consolidation Exception'

·    Amendments to IAS 1 'Disclosure Initiative'

·    Annual Improvements to IFRSs 2012-2014 Cycle

·    Amendments to IAS 27: 'Equity Method in Separate Financial Statements'

·    Amendments to IAS 16 and IAS 38: 'Clarification of Acceptable Methods of Depreciation and Amortisation'

·    IFRS 11 Amendment: Accounting for acquisitions of interests in Joint Ventures

 

These new and amended standards and interpretations have not materially affected amounts reported or disclosed in the Group's financial statements for the six months ended 30 June 2016.

 

Standards and interpretations issued, but not yet effective

 

The following standards and interpretations, relevant to the Group, have been issued by the IASB, but are not effective for the financial year beginning 1 January 2016 and have not been early adopted by the Group:

 

                         



Effective date for periods




beginning on or after

IFRS 16 'Leases'1



1 January 2019

IFRS 9 'Financial Instruments'1



1 January 2018

IFRS 15 'Revenue from Contracts'1



1 January 2018

Amendment to IAS 7: Disclosure Initiative1



1 January 2017

Amendment to IAS 12: Recognition of Deferred Tax Assets for Unrealised Losses1



1 January 2017

1These standards amendments and improvements have not yet been endorsed by the European Union.

The Group does not currently expect any of these changes to have a material impact on the results, except as outlined below.

 

IFRS 9 'Financial Instruments'

The IASB The IASB issued the final version of IFRS 9 in July 2014, which reflects all phases of the financial instruments project. IFRS 9 introduces new requirements for the classification, measurement and impairment of financial instruments and hedge accounting, and will be adopted by the Group when it becomes mandatory in the European Union. The Group is currently reviewing the standard to determine the likely impact on the Group's consolidated financial statements.

 

IFRS 15 'Revenue from Contracts'

IFRS 15 'Revenue from Contracts with Customers', replaces all existing revenue requirements (IAS 11 Construction Contracts, IAS 18 Revenue, IFRIC 13 Customer Loyalty Programmes, IFRIC 15 Agreements for the Construction of Real Estate, IFRIC 18 Transfers of Assets from Customers and SIC 31 Revenue - Barter Transactions Involving Advertising Services) in IFRS and applies to all revenue arising from contracts with customers;  The Group is assessing the impact of IFRS 15 but currently expects that it will not have a material impact on the Group's results.

 

The Group is currently reviewing the above amendments to determine the likely impact on the Group's consolidated financial statements from the changes arising from these standards and interpretations. They are not expected to materially affect amounts reported or disclosed in the Group's consolidated financial statements , with the exception of IFRS 16 Leases, the full impact of which is still being considered.

 

2.2          Significant accounting judgements, estimates and assumptions

The preparation of the Group's consolidated financial statements requires management to make judgements, estimates and assumptions that affect the reported amounts of revenues, expenses, assets and liabilities, and the accompanying disclosures, and the disclosure of contingent liabilities at the date of the consolidated financial statements. Estimates and assumptions are continuously evaluated and are based on management's experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. Uncertainty about these assumptions and estimates could result in outcomes that require a material adjustment to the carrying amount of assets or liabilities affected in future periods.

 

The Group has identified the following areas where significant judgements, estimates and assumptions are required.  Further information on each of these areas and how they impact the various accounting policies are described below and also in the relevant notes to the financial statements.

 

Oil & gas prices

Future oil & gas prices are based on latest internal forecasts, benchmarked with external sources of information, to ensure they are within the range of available analyst forecasts. Where existing sales contracts are in place, the effects of such contracts are taken into account in determining future cash flows.

 

Commercial reserves

Management is required to assess the level of the Group's commercial reserves together with the future expenditures to access those reserves, which are utilised in determining the amortisation and depreciation charge for the period and assessing whether any impairment charge is required. The Group employs independent reserves specialists who periodically report on the Group's level of commercial reserves by evaluating the estimates of the Group's in house reserves specialists and where necessary referencing geological, geophysical and engineering data together with reports, presentation and financial information pertaining to the contractual and fiscal terms applicable to the Group's assets. In addition the Group undertakes its own assessment of commercial reserves, using standard evaluation techniques and related future capital expenditure by reference to the same datasets using its own internal expertise. The estimates adopted by the Group may differ from the independent reserves specialists' estimates where management considers that adjustments are appropriate in the circumstances. The last assessment by its independent reserves specialist was as at 1 January 2016.

 

Intangible exploration and valuation assets

The application of the Group's accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely, from either future exploration, development or asset sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves.

 

 

Management is also required to assess impairment in respect of exploration and evaluation assets. The intangible exploration and evaluation assets note discloses the carrying value of such assets. The triggering events for impairment are defined in IFRS 6. In making the assessment, management is required to make judgements on the status of each project and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available.

 

Where an indicator of impairment exists, a formal estimate of the recoverable amount is made.  The assessments require the use of estimates and assumptions such as long-term oil prices, discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, and reserves.  These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or CGUs.

 

Oil and gas properties

Management is required to assess impairment in respect of oil and gas property assets at least annually with reference to indicators in IAS 36 'Impairment of Assets'. The oil and gas properties note discloses the carrying value of such assets. In making the assessment, management is required to estimate the recoverable amount for each asset held and compare that value to the net carrying amount of the asset at the balance sheet date. Such a review is done at least annually. This requires estimates to be made of in particular: future commodity prices, production volumes, capital/operating expenditure and appropriate pre-tax discount rates. Details of the Group's oil and gas properties are provided in note 10 to the consolidated Financial Statements. 

 

Where an indicator of impairment exists, a formal estimate of the recoverable amount is made.  The assessments require the use of estimates and assumptions such as long-term oil prices, discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, and commercial reserves.  These estimates and assumptions are subject to risk and uncertainty. Therefore, there is a possibility that changes in circumstances will impact these projections, which may impact the recoverable amount of assets and/or CGUs.

 

Provision for decommissioning

Decommissioning costs are uncertain and cost estimates can vary in response to many factors, including changes to relevant legal requirements, the emergence of new technology or experience at other production sites. The expected timing, extent and amount of expenditure may also change. Therefore significant estimates and assumptions are made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions established which would affect future financial results.

 

The estimated decommissioning costs are reviewed annually by an external expert and the results of this review are then used for the purposes of the financial statements.

 

Provision for environmental clean-up and remediation costs is based on current legal and contractual requirements, technology and price levels.

 

Share-based payments

Management is required to make assumptions and use their judgement when determining the inputs used to value share-based payment arrangements made during the year. Details of the inputs adopted when valuing share-based payment arrangements can be found in the Group's Annual Report for the year ended 31 December 2015. Management bases these assumptions on observable market data such as the Group's share price history and risk free interest rates offered on Government bonds.

 

Recovery of deferred tax assets

Judgement is required to determine whether deferred tax assets are recognised in the statement of financial position. Deferred tax assets, including those arising from unutilised tax losses, require management to assess the likelihood that the Group will generate sufficient taxable profits in future periods, in order to utilise recognised deferred tax assets. Assumptions about the generation of future taxable profits depend on management's estimates of future cash flows. These estimates are based on forecast cash flows from operations and judgement about the application of existing tax laws in each jurisdiction. To the extent that future cash flows and taxable income differ significantly from estimates, the ability of the Group to realise deferred tax assets could be impacted. The Group establishes tax provisions, based on reasonable estimates, for possible consequences of audits by the tax authorities of the respective countries in which it operates. The amount of such provisions is based on various factors, such as experience with previous tax audits and differing interpretations of tax regulations by the taxable entity and the responsible tax authority.

 

Special remuneratory benefit tax

The Group is subject to a special remuneratory benefit tax in Thailand, the rate for which depends on the annual revenue per cumulative metre drilled. Accordingly the tax rate to be applied in calculating the Group's deferred special remuneratory benefit tax depends on management's forecast of future revenues and drilling activities.

 

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 2016

Africa


Asia


Other


Total

$'000


$'000


$'000


$'000


Revenue (external)

-


52,097


-


52,097


Operating profit/(loss)

9,054


(60,141)


(18,157)


(69,244)


Net finance (expense)/income

(257)


(470)


347


(380)


Profit/(loss) before tax

8,797


(60,611)


(17,810)


(69,624)


Taxation

(2,614)


23,791


-


21,177


Profit/(loss) after tax

6,183


(36,820)


(17,810)


(48,447)











Total assets

766,227


1,135,867


329,684


2,231,778


Six months ended 30 June 2015

Africa


Asia


Other


Total

$'000


$'000


$'000


$'000

Revenue (external)

-


80,881


5,614


86,495

Operating profit/(loss)

(91,755)


16,216


(35,500)


(111,039)

Net finance (expense)/income

68


19


(6,976)


(6,889)

Other financial losses

-


-


(5,367)


(5,367)

Profit/(loss) before tax

(91,687)


16,235


(47,843)


(123,295)

Taxation

6,399


-


(14,116)


(7,717)

Profit/(loss) after tax

(85,288)


16,235


(61,959)


(131,012)









Total assets

778,290


1,376,756


614,018


2,750,074

 

year ended 31 December 2015

Africa

Asia


Other


Total

$'000

$'000


$'000


$'000

Revenue (external)

-


161,090


-


161,090

Operating loss

(154,270)


(169,029)


(45,459)


(368,758)

Net finance (expense)/income

22


(9,471)


(1,213)


(10,662)

Other financial profits

-


3,372


-


3,372

Loss before tax

(154,248)


(175,128)


(46,672)


(376,048)

Taxation

6,980


46,631


(15)


53,596

Profit/(loss) after tax

(147,268)


(128,497)


(46,687)


(322,452)









Total assets

705,430


1,164,134


554,298


2,423,862

 

 

 

6 Months ended

30 June 2016

(Unaudited)

$'000


6 Months ended

30 June 2015

(Unaudited)

$'000


 

Year ended

31 December

2015

$'000








4

Revenue







Sales of crude oil

52,097


80,881


161,090


Realised settlement gains on hedging

-


5,614


-



52,097


86,495


161,090








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

23,241


10,519


31,797


- Royalty payable

4,087


7,713


14,548


- Depreciation and amortisation of oil and gas properties

34,235


45,664


80,943


- Movement in inventories of oil

(6,887)


603


1,528



54,676


64,499


128,816









(b)    Gain on farm-out







- Gain on farm-out

-


(245)


(245)









(c)     Exploration expenses







- Pre licence exploration costs

8,662


17,671


34,157


- Exploration expenditure written off (note 9)

60,069


77,196


148,980



68,731


94,867


183,137









(d)    General & administration expenses include:







- Operating lease payments - minimum    lease payments

1,504


2,555


7,400


-Corporate transaction expense

-


8,000


8,000


- Share-based compensation charge/(release)

(1,364)


1,428


4,594



140


11,983


19,994









(e)       Other operating (income)/expenses







- (Gain)/loss on disposal of assets

14


145


703


- Depreciation of other property plant and

 equipment

1,343


2,894


4,184


- (Release)/Provision for exiting contract1

(10,000)


20,000


20,000


- Other

63


-


377



(8,580)


23,039


25,264

 

1 The release of the provision relates to the reduction in the settlement costs, from $20m to $10m, agreed for the exit from the PSC in Kenya.

 

6 Months ended

30 June 2016

(Unaudited)

$'000


6 Months ended

30 June 2015

(Unaudited)

$'000


 

Year ended

31 December

2015

$'000

 

6

 

Net finance (expense)/income














Interest income on short-term bank deposits

1,044


1,118


1,673


Interest expense on long-term borrowings

(8,530)


(8,460)


(18,651)


Less: Interest capitalised

8,711


1,552


1,552


Unwinding of discount (note 17)

(92)


(613)


(1,250)


Net foreign currency exchange (losses)/gains 

(1,513)


(486)


6,014



(380)


(6,889)


(10,662)

 

 

7

 

Other financial (gains)/losses














Realisation settlement gains on hedging

-


-


17,091


Loss relating to oil derivatives

-


(5,649)


(14,001)


Gain on bond redemption (note 16)

-


282


282



-


(5,367)


3,372

 

As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000









8

Taxation
















(a)     Taxation charge
















Current income tax:








UK Corporation tax


-


-


-


UK Corporation tax - adjustment in respect of prior periods


-


(413)


-


Foreign tax:








Special remuneratory benefit


3,305


16,700


19,610


Other foreign tax


2,048


14,341


4,719


Foreign tax - adjustment in respect of prior periods


4,342


-


297


Total current income tax charge


9,695


30,628


24,626










Deferred tax:








Special remuneratory benefit


(4,724)


(5,911)


(43,603)


Other foreign tax


(26,148)


(17,000)


(34,619)


Total deferred tax (credit)/charge


(30,872)


(22,911)


(78,222)


Total tax (credit)/charge in the income statement


(21,177)



(53,596)


 

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 2016 was 10% (30 June 2015: 35%, 31 December 2015: 28%). 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.


 

(b)    Reconciliation of the total tax charge
















The tax (credit)/charge recognised in the income statement is reconciled to the Group's weighted average tax rate of 39% (30 June 2015: 23%, 31 December 2015: 36%).  The differences are reconciled below: 










Loss from operations before taxation


(69,624)


(123,295)


(376,048)


Loss from operations before taxation multiplied by the Group's applicable weighted average tax rate of 39% (30 June 2015: 23% , 31 December 2015: 36%)


(26,876)


(28,358)


(138,125)


Tax effect of SRB


(710)


8,350


(11,997)


Tax effect of share of profit of investments accounted for using the equity method


(1,409)


(2,033)


(3,610)


Non-deductible (income)/expenditure


(1,667)


22,720


88,168


Unrecognised deferred tax assets


821


8,337


10,742


Prior year adjustments


5,522


(413)


297


Other adjustments


3,142


(886)


929


Total tax  (credit)/charge in the income statement


(21,177)


7,717


(53,596)

 

 

 

 

 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:

 

As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000










(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 Statement of Comprehensive Income as follows:










Loss from operations before taxation


(69,624)


(123,295)


(376,048)


Add back losses from operations before taxation for activities outside of Thailand


13,039


143,456


296,547


(Loss)/ profit from operations before taxation for activities in Thailand


(56,583)


20,161


(79,501)


Deduct share of profit from investments accounted for using the equity method


(2,818)


(4,066)


(7,219)


Profit before taxation for activities in Thailand


(59,401)


16,095


(86,721)


Applicable rate of special remuneratory benefit


10%


35%


28%


Tax at the applicable rate of special remuneratory benefit


(5,940)


5,633


(24,282)


Special reduction


-


176


(8,659)


Change in special remuneratory benefit average deferred tax rate


(1,710)


-


-


Change in special remuneratory benefit rate compared to current special remuneratory benefit rate


3,585


-


-


Prior year adjustment


1,180


-


-


Other


1,466


10,891


8,948


Total current special remuneratory benefit charge/(credit)


(1,419)


16,700


(23,993)

















 


(d)           Deferred income tax


















Deferred tax balances relate to the following:








Corporate tax on fixed asset timing differences


(207,741)


(275,969)


(236,247)


SRB tax on fixed asset timing differences


(7,133)


(25,089)


(9,498)


Exploration and evaluation assets


-


-


-


Fair value adjustment in respect of exploration expenses


-


-


-




(214,874)


(301,058)


(245,745)

 

As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000









9

Exploration and evaluation assets








 

Cost








Balance at the beginning of the period


879,914


764,933


764,933


Additions 1


72,416


76,167


131,961


Acquisition of subsidiary 2


-


132,000


132,000


Expenditure written-off 3


(60,069)


(77,196)


(148,980)


Balance at the end of the period


892,261


895,904


879,914










1 Additions in the period include exploration activities in: Equatorial Guinea - Block R ($31.1 million), Cote d'Ivoire - Block CI-513 ($18.0 million) and Malaysia - Block 2A ($6.0 million). Additions for the year ended 2015 included exploration activities in: Myanmar - Block AD03 ($28.3 million), Thailand - G4/50 ($19.7 million) and Equatorial Guinea - Block R ($18.3 million) and five Indonesian PSC licences from Niko Resources Limited ($25.3million). The licences acquired from Niko Resources were accounted for as an asset purchase as they did not meet the definition of a business combination in accordance with IFRS 3.

2 Acquisition of subsidiary

3 Expenditure write off for the period ended 30 June 2016 was $60.1 million. The most significant write off was in respect of Thailand - G4/50: loss of $57.3 million. The cash generating unit ('CGU') applied for the purpose of the impairment assessment is the Block. The recoverable amount for the 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 Blocks was budgeted or planned within the current licences terms.

Expenditure write off for the year ended 31 December 2015 was $149.0 million (30 June 2015: $77.2 million). The significant write offs included within the $149.0 million (30 June 2015: $77.2 million) are listed below: Expenditure write off in respect of Kenya: loss of $62.6 million - Block L9 (30 June 2015: $62.0 million), in respect of Gabon: loss of $12.5 million - Ntsina Block (30 June 2015: $12.1 million), loss of $17.8 million - Mbeli Block (30 June 2015: nil) and in respect of three Blocks in the Seychelles a loss of $24.4 million (30 June 2015: nil). The cash generating unit ('CGU') applied for the purpose of the impairment assessment is the Blocks. The recoverable amount for 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 Blocks was budgeted or planned within the current licences 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 of 15% (2015:15%). Adjustments to cash flows are made to reflect the risks specific to the CGU.

 

As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000









10

Oil and gas properties 








 

Cost








Balance  at the beginning of the period


869,852


-


-


Acquisition of subsidiary


-


827,131


827,131


Additions


15,365


11,607


42,721


Balance at the end of the period


885,217


838,738


869,852










Depreciation and amortisation








Balance  at the beginning of the period


(207,675)


-


-


Charge for the period


(34,235)


(45,664)


(80,943)


Charge for impairment1


-


-


(126,732)


Balance at the end of the period


(241,910)


(45,664)


(207,675)










Net book value








Balance at the beginning of the period


662,177


-


-


Balance at the end of the period


643,307


793,074


662,177










1 The 2015 impairment charge of $126.7m related to the Bualuang oil field in Thailand.

 

 

 

 

 



As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000









11

Inventory








Oil and condensates


8,414


2,452


1,527


Materials and consumables


49,744


43,444


48,689




58,158


45,896


50,216

 

As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000

 

12          

 

Cash and cash equivalents




 

 

 

 




Cash


116,114


126,539


116,060


Cash equivalents


291,112


481,668


498,509




407,226


608,207


614,569










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 $407.2 million (30 June 2015: $608.2 million and 31 December 2015: $614.6 million).

 

 

As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000









13          

Investments
















Short-term investments


-


100,000


-




-


100,000


-


 

Short-term investments consists of cash deposits that are made for varying periods of between three months and twelve months depending on the immediate cash requirements of the Group and earn interest at the respective short term investment rates. The fair value of short term investments is nil (30 June 2015: $100.0 million and 31 December 2015: nil).

 

 


As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000

 

14          

 

Trade and other payables
















Trade and other payables


17,589


18,927


22,310


Accruals and deferred income


72,863


112,364


91,350


Payables owed to joint operation partners


9,697


588


2,311




100,149


131,879


115,971









Trade and other payables are unsecured and are usually paid within 30 days of recognition.

 


As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000

 

 

15          

 

Interest-bearing bank borrowings







 









 


Long term balance at the beginning of the period


115,949


-


-

 


Short term balance at the beginning of the period


37,059


-


-

 


Acquisition of subsidiary


-


253,918


253,918

 


Less: amounts repaid during the period


(59,352)


(44,088)


(100,910)

 


Less: amounts due within one year


(5,389)


(53,332)


(37,059)

 


Total borrowings due after 1 year


88,267


156,498


115,949

 









 

Interest-bearing bank borrowings comprise a $350 million senior reserves based lending facility. The facility has been arranged for a period of seven years commencing in December 2012.

The senior reserves based lending facility is secured against certain of the Group's Thailand and Indonesia development and producing assets. There has been no breach of terms on the borrowing facility. The key terms of the facility are:

•    Initial facility amount of up to $350 million.

•    Financial covenants relating to the ratio of the loan balance outstanding to the net present value of cash flows of the secured assets and relating to the ratio of the loan balance outstanding to the net present value of cash flows during the life of the loan of the secured assets.

•    Financial covenants relating to the maximum amount of borrowings of the Group.

•    The Group may draw an amount up to the lower of the facility amount being $350 million as at 30 June 2016 or the borrowing base amount as determined by the forecast cash flows arising from the borrowing base assets of $94 million.

•    As at 30 June 2016 the facility available is $94 million (30 June 2015: $298.8m, 31 December 2015: $153m)

•    Interest accrues at a rate of between 3.70% and 4.20% plus LIBOR depending on the maturity of the assets. The borrowing base amount is re-determined on a semi-annual basis; with the Group further having the option to undertake two mid-period redeterminations in each year should it elect to do so.

•    No early repayment penalties.

•    Change of control provisions.

The acquisition of Salamander Energy plc by Ophir Energy plc on 3 March 2015 constituted a change of control under the terms of the facility. Prior to this transaction completing, a waiver was obtained from the lending banks such that the terms of the borrowing facility were not impacted at the date of completion.

 

 

 


As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000

 

16          

 

Bonds payable
















Balance at the beginning of the period


106,651


-


-


Acquisition of subsidiary: 9.75% Unsecured, callable bonds at $150 million par value


-


154,835


154,835


Redemption - 9.75% Unsecured, callable bonds at $45.2 million par value


-


(45,652)


(45,652)


Gain on redemption (note 7)


-


(282)


(282)


Coupon interest charged


5,109


2,580


9,510


Interest paid


(5,110)


(5,110)


(11,760)




106,650


106,371


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. On 5 May 2015, bond holders exercised put options at 101% for the redemption of bonds with a par value of $45.2 million.

 


Decommissioning and restoration of oil and gas assets

$'000


Litigation and      other claims

$'000


Other  provisions

$'000


 

 

Total

$'000

 

17          

Provisions


















As at 30 June 2015 (Unaudited)

64,597


26,350


22,792


113,739











Arising during the period

1,956


-


-


1,956


Unwinding of discount (note 6)

637




-


637


Foreign exchange revaluation

-


-


(179)


(179)


Amounts released

-


-


(1,226)


(1,226)











As at 1 January 2016

67,190


26,350


21,387


114,927











Arising during the period

1,312


-


-


1,312


Utilised/paid

-


-


-


-


Unwinding of discount  (note 6)

92


-


-


92


Amounts released

-


-


(11,387)


(11,387)











As at 30 June 2016 (Unaudited)

68,594


26,350


10,000


104,944











As at 30 June 2016 (Unaudited)









Current

-


26,350


10,000


36,350


Non-current

68,594


-


-


68,594



68,594


26,350


10,000


104,944











As at 1 January 2016









Current

-


26,350


21,387


47,737


Non-current

67,190


-


-


67,190



67,190


26,350


21,387


114,927











As at 30 June 2015 (Unaudited)









Current

-


26,350


22,792


49,142


Non-current

64,597


-


-


64,597



64,597


26,350


22,792


113,739










Decommissioning and restoration of oil and gas assets

The provision outstanding at 30 June 2016 is expected to fall due from 2035 onwards.

Litigation and Other Claims

Litigation and other claims consist of separate legal matters, including claims arising from trading activities, in various Group companies and at various stages of negotiation. The majority of any cash outflow from these matters is expected to occur within the next 12 months, although this is dependent on the development of the various legal claims. In the Directors' opinion, after taking appropriate legal advice, the amounts provided at 30 June 2016 represent the best estimate of the expected loss.

Other provisions

Amounts provided at 30 June 2016 comprise:

·    $10.0 million provision representing the unavoidable, least net cost of exiting a contract. The cost is expected to be incurred within the next 12 months.

 

 


As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000








18

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 2015: 593,810,795)

3,061


2,474


2,474


 

Nil ordinary shares issued 0.25p each during the period (30 June and 31 December 2015: 152,208,6121)

-


587


587


746,019,407 ordinary shares of 0.25p each

(30 June and 31 December 2015: 746,019,407)

3,061


3,061


3,061

 

1 152,208,612 ordinary shares issued in consideration for the Salamander acquisition on 3 March 2015. The market value of the Company's shares on this date was: £1.39 ($2.14).

 


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.

 


As at
30 June 2016

(Unaudited)

Percentage Holding

 

19          

 

Investments accounted for using the equity method
















Company








APICO LLC






27.18%


APICO (Khorat) Holdings LLC






27.18%


APICO (Khorat) Limited






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
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000










Balance at the beginning of the period


130,200


-


-


Acquisition of subsidiary


-


167,000


167,000


Share of profit of investments


2,818


4,066


7,219


Impairment


-


-


(42,117)


Dividends received


(408)


(1,087)


(5,843)


Additions


1,176


3,941


3,941




133,786


173,920


130,200


 

 


As at
30 June 2016

(Unaudited)

$'000


As at

30 June 2015

(Unaudited)

$'000


Year ended

31 December

2015

$'000









 

20          

 

Reserves
























Treasury shares


(153)


(157)


(155)


Other reserves (note 21)


1,597,098


1,834,804


1,646,878




1,596,945


1,834,647


1,646,723


Non-controlling interest 1


(280)


(280)


(280)




1,596,665


1,834,367


1,646,443

 

1 The non-controlling interest relates to Dominion Uganda Limited, where the Group acquired a 95% shareholding during 2012.


Share premium 1
$'000

Capital redemption 2 reserve
$'000

Options premium 3 reserve
$'000

Consolidation  reserve
$'000

 

 

 

 

Merger 5    reserve

$'000

Equity 6 component on convertible bond
$'000

 

 

Foreign 7 currency translation reserve
$'000

Accumulated

profits /           (losses)
$'000

Total

 other reserves
$'000











21   Other reserves










As at 1 January 2015

807,427

62

50,214

(500)

341,792

669

6,240

490,000

1,695,904

Loss for the period, net of tax

-

-

-

-

-

-

-

(131,012)

(131,012)

Other comprehensive loss, net of tax

-

-

-

-

-

-

(1,049)

-

(1,049)

Total comprehensive loss, net of tax

-

-

-

-

-

-

(1,049)

(131,012)

(132,061)

New ordinary shares issued to third parties

-

-

-

-

325,545

-

-

-

325,545

Purchase of own shares 8

-

98

-

-

-

-

-

(56,109)

(56,011)

Share-based payments

-

-

1,427

-

-

-

-

-

1,427

As at 30 June 2015 (Unaudited)

807,427

160

51,641

(500)

667,337

669

5,191

302,879

1,834,804

Loss for the period, net of tax

-

-

-

-

-

-

-

(191,440)

(191,440)

Other comprehensive income net of tax

-

-

-

-

-

-

347

-

347

Total comprehensive loss, net of tax

-

-

-

-

-

-

347

(191,440)

(191,093)

Purchase of own shares

-

-

-

-

-

-

-

-

-

Exercise of options

-

-

-

-

-

-

-

-

-

Share-based payments

-

-

3,167

-

-

-

-

-

3,167

As at 1 January 2016

807,427

160

54,808

(500)

667,337

669

5,538

111,439

1,646,878

Loss for the period, net of tax

-

-

-

-

-

-

-

(48,447)

(48,447)

Other comprehensive loss, net of tax

-

-

-

-

-

-

31

-

31

Total comprehensive loss, net of tax

-

-

-

-

-

-

31

(48,447)

(48,416)

New ordinary shares issued to third parties

-

-

-

-

-

-

-

-

-

Purchase of own shares

-

-

-

-

-

-

-

-

-

Share-based payments

-

-

(1,364)

-

-

-

-

-

(1,364)

As at 30 June 2016 (Unaudited)

807,427

160

53,444

(500)

667,337

669

5,569

62,992

1,597,098











 

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 the current year the provisions of the Companies Act 2006 relating to Merger Relief (s612 and s613) were applied to the Salamander Energy plc acquisition.  The non-statutory premium arising on shares issued by Ophir as consideration has been recognised in the Merger reserve, by virtue of Ophir acquiring in excess of 90% of all classes of the acquiree's issued share capital.

 

In the prior year the provisions of the Companies Act 2006 relating to Merger Relief (s612 and s613) were applied to the March 2013 share placement and rights issue raising performed through a cash box structure. The 'cash box' method of affecting an issue of shares for cash is commonplace and enabled the Company to issue shares without giving rise to a share premium. The premium on shares issued, net of applicable transaction costs of $34.5 million, as part of the 'cash box' arrangement is instead recognised in the Merger Reserve. Following on from the completion of the Group's farm out of 20% of its interest in Tanzania Blocks 1, 3 & 4 in March 2014 Ophir Ventures (Jersey) Limited and Ophir Ventures (Jersey) No.2 Limited, which are wholly owned subsidiaries of the Company, redeemed the preference shares that had been acquired by the Company as part of the 'cash box' arrangement.  This has allowed the Company to realise $876.4 million of the Merger Reserve to accumulated profits / (losses) as the redemption of the preference shares was considered to be performed with qualifying consideration in the form of free cash and a readily recoverable receivable from Ophir Holdings Limited, a 100% owned subsidiary of the Company and beneficial holder of the Group's interest in Tanzania Blocks 1, 3 & 4. 

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        On 14 August 2014, the Company announced that the Board had approved a share buyback programme of up to $100 million of ordinary shares (the 'Programme'). During 2015, the Group repurchased 26,114,403 shares under the Programme for a total consideration of $56.1 million, including costs of $0.3 million. The remaining facility as at 30 June 2016 was $nil (31 December 2015: nil).


22     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:

 



as at 30 June 2016

(Unaudited)

$'000


As at 30 June 2015

(Unaudited)

$'000


year ended
31 december 2015

(Unaudited)

$'000

Due within one (1) year


45,128


32,997


39,010

Due later than one (1) year but within two (2) years


26,180


50,986


30,350

Due later than two (2) years but within five (5) years


21,480


12,145


17,680



92,788


96,127


87,040

23     Contingent liabilities

 

An individual has commenced claims against the Group relating to the evaluation and subsequent disposal of an interest that was held in exploration blocks within the portfolio. Preliminary court hearings for applications relating to the claims have been held, and, to date, no material rulings have been made.  The Group is awaiting the schedule for the full trials and it is not practicable to state whether any payment obligation may arise. The Group has taken the view that the actions are without merit and accordingly 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.

 

                                                  

24     Events after the reporting period

 

There are no events after the reporting period.

 

 


 

Company Information

 

 

Directors

 


Chairman (Non-Executive)

 

William (Bill) Schrader

 

Executive Directors

 

Dr Nicholas (Nick) Cooper - Chief Executive Officer

Dr William (Bill) Higgs - Chief Operating Officer

Anthony (Tony) Rouse - Chief Financial Officer

 

Company Secretary

 

Philip Laing

Independent Non-Executive Directors

 

Ronald Blakely

Dr Carol Bell

Alan Booth

Vivien Gibney

David Davies (Appointed 23 August 2016)

Dr Carl Trowell (Appointed 23 August 2016)





 

Registered Office and Head Office

 

Fourth Floor

123 Victoria Street

London SW1E 6DE

Telephone: +44 (0)20 7811 2400

 

Website: www.ophir-energy.com    

 

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:

Ernst & Young LLP

One More London Place

London SE1 2AF

United Kingdom

 

Solicitors:
Linklaters
One Silk Street
London EC2Y 8HQ
United Kingdom



Bankers:

HSBC Bank plc

70 Pall Mall

London SW1 5EY

United Kingdom

 

Financial PR Advisors:

Brunswick Group LLP
16 Lincoln's Inn Fields

London WC2A 3ED
United Kingdom

Corporate Brokers:

Bank of America Merrill Lynch

2 King Edward Street

London EC1A 1HQ

United Kingdom

 

Morgan Stanley
20 Bank Street
Canary Wharf
London E14 4AD

United Kingdom

 

 



1 See page 3


This information is provided by RNS
The company news service from the London Stock Exchange
 
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