9 March 2017

Ophir Energy plc

Full Year Results for the year ended 31 December 2016

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

"2016 saw Ophir adopt the simple maxim "find low, monetise smartly".  Our decision to re-orient the Group's activities around net asset value per share has changed our corporate mindset.  All activities are now focused on finding or developing hydrocarbons at the lowest cost and monetising promptly and swiftly; thereby maximising the margin realised for shareholders. In 2016, Ophir delivered the start-up of the Kerendan gas field, we advanced the Fortuna FLNG project towards FID and significantly reduced our G&A cost (for a third year running).

"We are looking for 2017 to deliver material milestones. A green light for Fortuna, expected in mid-2017, will unlock 345 MMboe for monetisation. Subject to the volume of gas we choose to term up, this could treble our Group 2P reserves in the process. Plans to sweat our Asian assets have the potential to monetise up to a further 80 MMboe over the next three years. 

"At the same time, Ophir will be resuming operated exploration and the Ayame-IX well in Côte d'Ivoire is expected to spud in May 2017. With production, development and exploration programmes gathering pace, Ophir is moving towards our ambition of being a sustainable explorer."

Financial Sustainability

·    Revenue of $107 million (2015: $178 million) with a further $15 million (2015: $17 million) for Sinphuhorm accounted for using the equity method

·    Cash generated from operations of $62 million(1) (2015: $113 million)

·  Cash on the balance sheet of $360 million (2015: $615 million, including short-term cash deposits)

·    Net cash on balance sheet of $160 million (2015: $355 million)

·    Achieved a further 35% reduction in net G&A costs

(1)       See Financial Review Sources and uses of funds summary table

Monetisation of Resource

·   Reached agreement with OneLNG to form a Joint Venture that will facilitate the development of the Fortuna gas field, Equatorial Guinea, with FID expected during mid-2017, monetising 345 MMboe

·    Worked over 1.8 million man hours incident free

·  Achieved 99.6% production uptime, leading to average daily production of 10,800 boepd (including Sinphuhorm),  in line with expectations

·    Completed a produced water debottlenecking project on the Bualuang field, Thailand

·    Expansion of Kerendan asset approved by Indonesian authorities

Finding Low

·    Ayame-1X exploration well in Cote d'Ivoire matured to drill-ready and will spud in 2Q 2017, targeting 234 MMbo of gross mean prospective resource

·     Added 158 MMboe of risked, drill-ready, prospective resource to the prospect inventory

·   Completed the Trepang 3D seismic survey in West Papua IV/Aru licences in Indonesia and matured a number of prospects to drill-ready

·   Commenced an onshore 3D seismic programme in Greater Kerendan area with a view to expanding this asset

·    Entered Mexico with a successful bid for Block 5 in the Mexico deepwater licensing round

A presentation for analysts will be held at 10.30am this morning. This will be webcast live through the link on the Company website: www.ophir-energy.com/investors. 

Ends

For further enquiries please contact:

Chief Executive Officer's review

Last year in this report we described how the upstream E&P sector had, in our view mistakenly, prioritised growth over returns through the last up-cycle. As we promised in early 2016, Ophir has reformed its business model. We have also adjusted our investment strategy and compensation structure to focus resolutely on Net Asset Value (NAV) per share. These reforms have been positively received by investors. As an organisation, we are determined that a more benign oil price environment will not distract us from what we consider to be the best approach to sustainable, through-cycle, growth in shareholder value.

Ophir's role in the value chain is to find molecules at the lowest possible cost and monetise them at the highest possible price, as promptly as is feasible. Upstream, like any other business, is about margins achieved, rather than daily spot prices. Focusing on assets with low breakeven prices, and then delivering healthy product margins through smart monetisation will sustainably create value through the cycle.

The monetisation model

The steps we took to put this 'find low, monetise smartly' model into practice were threefold:

Firstly, in order to improve our ability to 'find low', we needed both to significantly reduce our running costs and realign our exploration portfolio to search for barrels that break even at low prices. We delivered a material reduction in our G&A cost, improving efficiencies across the business. We also exited five exploration blocks that failed to meet our stricter investment criteria and entered three new blocks that did.

Secondly, we sharpened our monetisation focus, both through lowering opex on producing assets, and more rapid conversion of our substantial 2C resources into producing 2P reserves or, better still, cash. This focus saw us progress the Kerendan gas field to first gas, prepare the Bualuang oil field for the next phase of development and drive the Fortuna FLNG project closer to Final Investment Decision (FID). In total, these steps offer the potential to convert approximately 140 MMboe of 2C resources to 2P in 2017, more than trebling our current 2P reserves.

Thirdly, we transformed corporate behaviour by introducing our new NAV per share remuneration scheme for all employees. This compensation approach is, we believe, far better aligned to shareholders interests than a relative TSR metric in a cyclical industry. We have been tremendously encouraged by how the new approach has clarified investment decision-making and sharpened our allocation of people and capital. I would like to thank our shareholders for supporting this radical new scheme at our 2016 AGM.

Milestones in 2016

Ophir's progress in 2016 across these three areas has been rapid and substantial. We are convinced that the changes that Ophir made in early 2016 now position the Company to thrive in this new upstream environment and deliver sustainable, superior total shareholder return through the coming cycles.

In terms of finding at lowest cost, our model is to drive NAV growth through sustainable, prudent exploration that is consistent through the cycle. We believe that we can drill around two to three material, frontier exploration wells per annum, whilst maintaining sufficient technical rigour. We estimate that this drilling rate would represent 10-25% of total global, frontier drilling by the independent sector through the cycle.

I am pleased to say that we are now returning to operated exploration drilling. Preparations for the Ayame-1X well in Côte d'Ivoire started in 2016 to be ready for an expected spud in May 2017. This would represent Ophir's first deepwater operated well in almost three years. As with our upstream peers, the fact that our drilling targets are now competing for scarcer, but discretionary, risk capital allows more high grading and should deliver better risked outcomes from the portfolio.

In terms of monetising smartly, Ophir's exploration has, thus far, resulted in the discovery, and part-monetisation, of two, world-class assets in Tanzania and Equatorial Guinea.

In Tanzania, we have to date monetised the majority of our interests and have delivered a material return on our historic investment. In 2016, we saw a renewed push from the Tanzanian Government to deliver the LNG project and the introduction of a new operator in Shell. Both factors should accelerate the project towards an FID later this decade. In 2017, our focus in Tanzania remains to maximise shareholder returns from our remaining 20% stake.

In Equatorial Guinea, we have made material progress toward completing and financing an LNG value chain in the context of a challenging market. After frustrations in the first half of 2016, an innovative approach to value chain partnering and risk sharing unlocked the problem. A constructive dialogue with our midstream partner Golar LNG enabled us to find a solution that satisfies the trends emerging in LNG pricing, contracting, financing and risk- sharing. In November 2016 we signed a Shareholders' Agreement with OneLNG - a joint venture between Golar LNG and Schlumberger - to form a new Joint Venture (JV) that will finance and develop the Fortuna project.

The establishment of the JV means we can now move the Fortuna FLNG Project towards FID in mid-2017. At FID, the project NPV will be a healthy multiple of the $120 million of capital we are committing before first gas. Furthermore, the JV has been structured so that Ophir Energy plc will not take any additional balance sheet exposure or liabilities.

Ophir now has line of sight on its biggest potential monetisation step since the Tanzania partial divestment in 2014. It has been a long, difficult road but we are firmly on track for a mid-2017 FID, which will monetise approximately 345 MMboe of 2C resource. This will be one of a handful of global FIDs of a green-field LNG project in 2017.

Monetising resource in this challenging environment demonstrates Ophir's commercial acumen; a valuable complement to our skilled team of geo-scientists and their ability to efficiently find hydrocarbons.

At Ophir, we also recognise that capital return to shareholders needs to start as early as possible. Once we reach our goal of generating sufficient cash flow to be a sustainable explorer, we will be in a better position to consider making returns to our shareholders. The annuity-type cash flows that we will receive from the Fortuna FLNG asset mean that Ophir's sustainability, and therefore the predictability of capital returns, should become increasingly visible towards the end of the decade.

As I look ahead to trends for 2017, breaking down barriers between industry and value-chain players is a pre-requisite. The exploration director of a major oil and gas company recently put this best when they told us "now is a time for the industry to collaborate, as we are all in this together; we can compete again if necessary in the next decade". More exploration companies are recognising the benefits from working together, sharing data and knowledge to try to focus capital towards the best opportunities.

A second area that is rightly attracting increasing attention is the role of upstream players in the climate change challenge. At Ophir, we recognise that we cannot put our head in the sand. We are not about to transform to a renewable energy company, but we do see a need for modified thinking and we have spent time in 2016 developing a position on this. This will evolve, but the topic is now on the Board's agenda.

Ophir is now better-placed than we have been for several years. I firmly believe, with the changes we have made to our business model, our culture and our approach to resource allocation that we can begin to deliver material returns for our shareholders.

I would like to thank Ophir's investors for their support and patience, and Ophir's team for their energy, loyalty and bright ideas despite the tough times.

As described in the Chairman's section, Nic Smith stood down as Chairman in 2016 to be replaced by Bill Schrader. I thank Nic for all his guidance and support to Ophir since its inception.

Regardless of what may, or may not, happen to commodity prices in 2017, the changes that Ophir made in 2016 mean that we can look forward with confidence and optimism.

Review of operations

As the organisation becomes increasingly focused on creating growth in NAV per share, we are applying greater discipline when allocating capital to our operating activities. Our first priority is in safely maximising the value of the cash returns from our production base. We can then think about where else in the portfolio to deploy that capital in the pursuit of further value creation.

During 2016 we have invested in additional facilities at the Bualuang field to improve the production capacity of the infrastructure; brought the Kerendan gas field onstream, diversifying our production base; progressed the Fortuna FLNG project towards FID; and continued to build the prospect inventory to provide drilling options for 2017/2018.

As we look ahead through 2017, we will continue to invest in both Bualuang and Kerendan to increase the cash generation of the asset base. This is expected to lead to cash flow materially higher than in 2016. The Fortuna FLNG project should move through FID in mid-2017, providing a clear timeline to first production and cash flow.

We will recommence exploration drilling in 2Q 2017 with a well on the Ayame-1X prospect in Côte d'Ivoire.

Taken as a whole, we are confident that we will unlock further value in our production base during 2017 and hope that we can also create value through opening up a new play in Côte d'Ivoire.

Health, Safety, Security and Environment

Ophir is committed to protecting the health, safety and security of our workforce and environments in which we work.

We do this through the deployment of HSSE risk management systems that include the use of leading indicators to test the robustness of our controls. Over 1.83 million hours were worked during 2016 with no recordable injuries or illnesses and no loss of containment events. These were excellent achievements.

Resource and reserves monetisation

Let us look at the application of our strategy at an operational level. Reliable, diversified cash flow from our production base is an important part of our strategy to become a sustainable explorer. We have invested, and will continue to invest, 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. As such, we may look to partially or wholly monetise on discovery or prior to significant investment to deliver the highest risk-weighted returns to shareholders.

Bualuang, Thailand (20.9 MMbo 2P, 17.8 MMbo net 2C)

Our strategy for managing the Bualuang field is to maximise cashflow through safe, reliable and cost-efficient production operations, combined with the appropriate capital deployment to further develop contingent resources. Bualuang is currently the most cash-generative asset in the Ophir production portfolio. In 2016, it generated $58 million of cash from average daily production of 8,700 bopd.

Our main focus at Bualuang during the year was to complete a water debottlenecking project that increased water handling capability by 50% to enable an increase in production and, consequently, cash generation.

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

As we look forward, the key challenge at Bualuang is how we create further value and increase the cash generation of the field. The ocean bottom node 3D seismic data, acquired in 2015 to image under the platform, was processed and interpreted in 2016 and is key to determining how we unlock additional value from the field.

In 2017, we will complete a small infill drilling programme consisting of two development wells. This will see old well stock recycled to target new locations with the goal to grow production by around 1,400 bopd. The investment in this programme will be c. $12 million and is expected to add $23 million to the NPV of the project and payback within 12 months.

We will also drill a further well targeting prospective resource in the Bualuang field.

We are also in the final technical and commercial analysis stage of the opportunity to expand the production capacity at Bualuang by the installation of a simple, low-cost platform. Additional well slots will enable the targeting of locations to convert prospective and contingent resources to reserves. We expect to be in a position to make an FID on the next phase of development in 2Q 2017.

Kerendan, Indonesia (15.9 MMboe 2P, 60.3 MMboe net 2C)

The primary challenge at Kerendan now that the field is producing, is to seek innovative ways to monetise the 457 Bcf of gross 2C contingent resource not covered by the initial gas sales agreement (GSA).

The field produced at an average of 768 boepd over the period in 2016 that it was producing, but is expected to ramp up to full contract volume of closer to 20 MMscfd in 2017, providing additional cash flows. The offtaker contracted to take 16 MMscfd from 11 January 2016 and, under the take or pay provision in the GSA, a receivable of $17 million has been accrued. This was settled in full in February 2017.

A significant step forward in monetising the additional 2C resource in the Kerendan area occurred in late 2016 with SKKMigas approving the West Kerendan-1 expansion plan.

This will allow an additional 40 Bcf to be monetised that will grow production by 7 MMscfd from 2019. Making further progress on the monetisation of the 457 Bcf of gross contingent resource, not covered by the first GSA, is an area of focus for 2017. Safe completion of the onshore 3D seismic acquisition programme, forecast to complete in Q4 2017, is a key step on this pathway. These data will allow for better definition of the Kerendan field to give greater certainty around resource volumes, which should ultimately lead to SKKMigas approving the sale of additional gas volumes.

Sinphuhorm (7 MMboe 2P, 21.3 MMboe net 2C)

Gas production from Sinphuhorm was 10% ahead of budget at 1,900 boepd. This was principally as a result of the poor performance from the competing hydropower sector.

Fortuna, Equatorial Guinea (400.7 MMboe net 2C)

The Fortuna project was the asset most in the spotlight during 2016 as we sought to find a way to monetise the 400 MMboe of net 2C resource we have discovered in the play to date. Our focus has always been on monetising this asset in a manner that maximises value creation for our shareholders.

We have continued to move this project forward for one simple reason - the point forward returns are excellent, as it is a low-cost project with a world-class reservoir. Admittedly, we have had our setbacks on this project, no more so than in the early part of 2016 when Schlumberger withdrew from a planned upstream farm-in. Having worked closely with our then midstream partner, Golar LNG, to find a funding solution for the midstream part of the project, we were delighted to sign a Shareholders' Agreement with OneLNG in November 2016 for the formation of a Joint Venture that will develop and finance the Fortuna FLNG project.

OneLNG is a joint venture owned by Golar LNG and Schlumberger to help monetise stranded gas assets. We now have an integrated project with Ophir and OneLNG aligned across the value chain. Ophir will not invest more than $120 million of the $2 billion of capital expenditure required to get to first gas and we expect to generate a return of over 5x on this investment.

Since announcing the JV in November 2016 we have made good progress against the remaining milestones. The Umbrella agreement between the Fortuna JV and the Government of Equatorial Guinea is expected to be signed during 1Q 2017. This defines the legal and fiscal framework for the project.

A term sheet has been signed for the provision of the debt facility with a consortium of Chinese banks. We have now moved to the documentation phase and expect to close the facility during 2Q 2017.

The discussions with offtakers remain on-going and are expected to be closed out imminently.

We expect to issue a shareholder Circular during 2Q 2017 with FID remaining on schedule for mid-2017.

Blocks 1 and 4, Tanzania (500.2 MMboe net 2C)

In Tanzania, Shell took over the operatorship from BG Group in March 2016 and has since undertaken a review of the project plan, the development scope and the cost stack of the project.

Separately, since the elections in Tanzania in late 2015, the new Government has taken a more pro-active, hands-on approach to delivering the project. An integrated negotiating team, with representatives from all the key ministries, has been established, with the remit to deliver the required project agreement for the onshore LNG plant. Once this is agreed, there will be a clear legal framework under which the development can be moved forward.

After completing the final exploration commitment wells on Blocks 1 and 4 in late 2016, the Minister of Energy awarded an extension of Block 1 for a further three and a half years to provide sufficient time to complete pre-FEED and FEED ahead of investment approval. An extension for Block 4 is expected later in 2017. Ophir will continue to determine the optimum way to monetise the asset to deliver value for shareholders.

Exploration

Ophir's strategy is to create value for shareholders through finding resources at low cost and monetising them smartly in the way that maximises the value created.

We have been actively maturing the best prospects on the plays we have high-graded, adding new plays to compete for capital with the existing opportunities. We have looked at numerous data rooms in the past three years to rank the best opportunities. As a result, Ophir has positions in a number of high graded plays, all of which have prospects that have cleared commercial and technical thresholds and have increased the Group's risked prospective resources by 158 MMboe.

During 2016 we entered three new licences. The first of these was a new country entry in Côte d'Ivoire when we signed a PSC for Block CI-513.

The Ayame-1X prospect will spud in 2Q 2017 and we are currently carrying mean prospective recoverable resource of 234 MMbo with a 23% geological chance of success. The well will be drilled by the Seadrill West Saturn rig and the gross cost is expected to be $30 million. It is a stratigraphic prospect testing an extension of a proven petroleum system in the adjacent block and the main risk is trap effectiveness.

We also entered the DW-2A licence in Malaysia and will take a drill or drop decision in 1H 2017.

Our third new licence entry was in Mexico, which followed work by our Global New Ventures team screening opportunities outside our Asian and African heartland. Our interest in Mexico was a result of the liberalisation of the energy sector, which meant that for the first time in nearly 80 years international companies would be able to bid for acreage in Mexican waters of the Gulf of Mexico. Fewer than 45 deepwater exploration wells have been drilled in Mexico compared with over 1,200 on the US side, creating a rare opportunity to access an under-explored, but proven world-class basin. The basin also screened well from a commercial basis and there is a clear path to monetisation.

Ophir is part of a Murphy-operated consortium, also containing PC Carigali (part of Petronas) and Sierra Oil & Gas, that won the rights to Block 5 in the first deepwater licence round in December 2016. Drilling is not expected to take place until 2019 and the net cost to Ophir of the first phase work programme is limited.

In Myanmar, we have matured the prospect inventory to drill-ready status. The play looks to be comprised of sands in low relief channel systems leading us to believe that Myanmar will likely be developed by the aggregation of gas fields. We are currently seeking to farm-down to a strategic partner and we view this as a pre-requisite to drilling.

In Equatorial Guinea, the southwest portion of Block R contains a potential extension of an oil play in the neighbouring block which is operated by an IOC. The operator of the adjoining block completed a 3D seismic survey in 2016 that was extended into Block R. These data have been processed and our geoscientists, along with those of the operator, are reviewing the prospectivity ahead of a decision on whether to drill a well.

In Indonesia, we safely completed the offshore Trepang 3D seismic survey on the West Papua IV and Aru licences in 4Q 2016.

We also completed the reprocessing of existing seismic data over the West Papua IV and Aru licences which has enabled us to mature a number of leads to prospects.

In Gabon, we have extended the Nkouere and Nkawa licences and are using the Olumi Rouge 3D seismic data to mature a new outboard play. We believe this play has multi-billion barrel potential and we are currently seeking to farm-down to a partner prior to entering into the second phase of the exploration licence.

Financial review

Sources and uses of funds summary

¹ Capex is adjusted to eliminate non-cash amounts for decommissioning for 2016 of $19.2 million (2015: $1.5 million) and capitalised interest for 2016 of $8.7 million (2015: $1.5 million).

Summary

As detailed in the Chief Executive Officer's review, our strategy is to be a sustainable explorer, focused on delivering NAV per share growth, by finding resources at low cost and then monetising them smartly in the way that maximises the value created. This requires us to generate sufficient cash flow over time, through a combination of maximising cash flow from our production assets and the monetisation of our exploration success, to fund a sustainable exploration programme.

Our first step to build this cash flow, was the acquisition of Salamander Energy in early-2015. This transaction provided Ophir with two producing assets in Thailand, Bualuang and Sinphuhorm, and a development asset in Indonesia, Kerendan, which came onstream in August 2016.

During 2016, we took a further step towards achieving our objective of becoming a sustainable explorer. Through our agreement with OneLNG, we will form a Joint Venture (JV) to facilitate the financing, construction and development of the integrated Fortuna project in Equatorial Guinea. This provides a framework whereby we can now move forward to commercialise the asset with a 33.8% equity interest in the JV. Through these arrangements, we have limited our capital and balance sheet exposures to a maximum of $120 million. We expect to take FID on the project by mid-2017 and the asset is expected to be on-stream mid-2020 delivering net cash flow to us of approximately $140 million per year (at an indicative FOB gas price of $6.00 MMbtu). The cash flow generated from Fortuna, along with the cash flow from our Asian production base, will see us broadly achieve our strategic objective of becoming a sustainable explorer.

Our principal financial goals are therefore to ensure that we preserve our balance sheet strength and maintain sufficient liquidity between now and Fortuna coming on-stream. In the meantime, funds will be invested as a priority to the further monetisation of our existing asset base with our exploration efforts being scaled according to the availability of residual capital.

Additionally, during 2016 we took further steps to preserve our liquidity by lowering our capital and operating cost base. We also reduced our gross administration cost base with a further reduction year on year (excluding one-off restructuring costs) of 31%.

Commodity prices strengthened during the second half of the year with the OPEC agreement in November further underpinning positive sentiment around oil prices. Brent recovered from a low of $27 per barrel in January to a high of $57 per barrel in December, and averaged $45 per barrel for the year. Brent pricing has been more stable in early 2017 than for some time, but the outlook remains cautious, and we will therefore continue to scale our future programmes according to our capital constraints until we have secured a sustainable cash flow.

Net sources of funds

2016 working interest production was in line with guidance at 10,800 boepd. This comprised 8,700 bopd from Bualuang and our first contribution from Kerendan which averaged 200 boepd for the year. In addition, 1,900 boepd was produced from Sinphuhorm (which is accounted for using the equity method).

Revenue (including realisation of hedges) from Bualuang totalled $107 million or $38 per barrel (2015: $178 million or $47 per barrel). With a breakeven for 2016 of $15 per barrel, Bualuang delivered positive post-tax funds flow of $58 million or $18 per barrel (2015: $106 million or $34 per barrel). The Kerendan field came onstream in August, with pre-production operating costs being charged to the income statement in 2016, Kerendan utilised net funds of $8 million. However, this amount was more than offset by recognising $17 million of deferred income to the balance sheet for the PLN take-or-pay obligation for volumes not drawn-down since the commencement of the GSA on 11 January 2016. The take-or-pay amount was settled in full by PLN in February 2017.

Full-year 2016 net sources of funds from production totalled $62 million (2015: $113 million), a 45% reduction year-on-year predominantly due to lower commodity prices.

With an improved commodity price outlook in 2017 and the Kerendan asset on-stream for the full year, post-tax funds flow from production is forecast to increase to $80-120 million or $18-27 per barrel.

Uses of funds

The Group's primary investments during 2016 were:

• Exploration of $76 million (2015: $140 million) including:

-          Acquisition of Côte d'Ivoire Block CI-513 ($20 million)

-        Myanmar AD-03 - well planning and Environmental Impact Assessment ($9 million)

-        Acquisition of Malaysia Block 2A ($8 million)

-        Indonesia - seismic data acquisition on the West Papua IV and Aru blocks ($8 million)

• Monetisation of resource of $80 million (2015: $68 million) comprising predominantly:

-          Tanzania, Blocks 1 and 4 - drilling and pre-development spend ($22 million)

-          Equatorial Guinea, Fortuna - Front End Engineering Design ($42 million)

-          Thailand, Bualuang - water debottlenecking project ($12 million)

Of the 2016 exploration expenditures, we charged and wrote-off $6 million (2015: $24 million) to the income statement. In addition, we wrote-off prior year expenditures of $94 million (2015: $125 million) following our decision to relinquish the G4/50 licence in Thailand and assessing the portfolio in Indonesia.

Our cost reduction programme saw gross administration cost reduce by a further 31% in 2016. This is reflected in our net administration expense reducing to $13 million (2015: $31 million), a reduction of 35% after eliminating one-off restructuring costs of $2 million in 2016 (2015: $14 million).

We incurred interest charges during 2016 of $14 million (2015: $16 million) against average gross debt of $230 million, giving rise to an average cost of debt of 7%. We took steps in 2016 to lower our borrowings thus reducing the negative interest carrying cost.

Overall, uses of funds for 2016 totalled $183 million (2015: $199 million).

Looking ahead to 2017, our capital expenditure is forecast at $125-175 million with plans including:

-          Thailand, Bualuang - infill drilling programme ($24 million)

-          Côte d'Ivoire - drilling of the Ayame-1X exploration well ($16 million)

-          Equatorial Guinea - initial funding for the Fortuna JV ($25 million)

Longer term, the Group's future financial commitments beyond 2017 are limited to $33 million (2016: $48 million) against agreed exploration work programmes.

Debt and net debt

During 2016 we reduced our total debt outstanding by repaying $59 million of our reserve based lending facility. This gave rise to outstanding debt at year-end 2016 of $200 million. This comprised of our reserves based lending facility of $93 million (2015: $210 million) and our high yield Nordic bond of $107 million (2015: $107 million).

In late 2016, we commenced the process of refinancing our debt facilities. This process is expected to complete in 2Q 2017 with an increase to our borrowing capacity.

Our balance sheet therefore remains robust with closing gross cash of $360 million (2015: $615 million, including short-term cash deposits) and net cash at year-end 2016 of $160 million (2015: $355 million). We expect to remain approximately gross cash neutral in 2017 with our capital expenditure programmes covered by a combination of funds generated from our production assets and additional cash made available through the refinancing of the debt facilities. We currently forecast that gross cash will be $375-425 million and that net cash will be $100-125 million at year-end 2017.

The Directors have also considered the longer-term viability of the Company to end-2020. Based on their assessment, the Directors have a reasonable expectation that the Company will be able to continue in operation and meet its liabilities as they fall due.

Consolidated income statement and statement of other comprehensive income

For the year ended 31 December 2016

The consolidated financial statements of Ophir Energy plc (registered number 05047425) were approved by the Board of Directors on 8 March 2017.

On behalf of the Board:

Nick Cooper

Chief Executive Officer

Tony Rouse

Chief Financial Officer

Notes to the 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 with company number 05047425. 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 Group's consolidated financial statements for the year ended 31 December 2016 were authorised for issue by the Board of Directors on 8 March 2017 and the consolidated statement of financial position was signed on the Board's behalf by Nick Cooper and Tony Rouse.

2.     Basis of preparation 

The consolidated financial statements of the Group have been prepared in accordance with IFRS as issued by the International Accounting Standards Board and adopted by the European Union (EU), IFRIC Interpretations and the Companies Act 2006 applicable to companies reporting under IFRS.

The consolidated financial statements are prepared on a going concern basis.

The consolidated financial statements have been prepared under the historical cost convention, modified by the revaluation of certain derivative instruments measured at fair value. The consolidated financial statements 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 abbreviated 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 2016.

3.     Segmental  analysis

The Group's reportable and geographical segments are Africa, Asia and Other. The other segment includes the corporate centres in the UK, Australia and Singapore.

Segment revenues and results

The following is an analysis of the Group's revenue and assets by reportable segment:

Non-current operating assets

The non-current operating assets for the UK are $2.7m. (2015: $4.0 million). The non-UK, non-current operating assets are $1,010.2 million (2015: $1,507.6 million). Included in the non-UK, non-current operating assets is Thailand which makes up $421.3 million (2015: $455.7 million).

4.    Exploration and evaluation assets

1   Additions for the year ended 31 December 2016 include exploration activities in: Equatorial Guinea - Block R ($41.5 million), Côte d'Ivoire - 513 ($19.6 million), Tanzania - Blocks 1 & 4 ($22.7 million), Myanmar - Block AD03 ($8.7 million) and Malaysia -Block 2A ($7.7 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   Expenditure written off in the year was ($100 million). The most significant write off was in respect of Thailand - G4/50: loss of $57.6m and Indonesia: loss of $37m.  The 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.

     Expenditure written off for the year ended 31 December 2015 was $149.0 million. The significant write offs included within the $149.0 million are listed below:

Expenditure write off in respect of Kenya: loss of $62.6 million - Block L9, in respect of Gabon: loss of $12.5 million - Ntsina Block, loss of $17.8 million - Mbeli Block and in respect of three Blocks in the Seychelles a loss of $24.4 million. The 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.

5.    Oil and gas properties

1   Additions in 2016 are stated net of a $19.2 million decommissioning remeasurement.

2   The 2016 Impairment reversal was due to increased reserves related to the Bualuang oil field in Thailand which has a recoverable amount of $410.7m based on management's estimate of value in use. The discount rate used was 15% (pre-tax).

The 2015 impairment charge of $126.7 million related to the Bualuang oil field in Thailand which had a recoverable amount of $387.2 million based on management's estimate of value in use. The discount rate used was 15% (pre-tax).

6.    Net debt

At the balance sheet date, the bank borrowings are calculated to be repayable as follows: