FAR LIMITED

Annual Report 2017

FAR builds on solid foundations

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04 Company Highlights
06 Chairman’s Review
08 Operati ons Review
22 Governance and Sustainability
23 Community and Social Programs
24 Directors’ Report
40 Auditor’s Independence Declarati on
41 Independent Auditor’s Report
45 Directors’ Declarati on
46 Consolidated Statement of Profi t or Loss and Other Comprehensive Income
47 Consolidated Statement of Financial Positi on
48 Consolidated Statement of Changes in Equity
49 Consolidated Statement of Cash Flows
50 Notes to the Financial Statements
77 Supplementary Informati on
78 Corporate Directory

Our vision

Create long term value through oil and gas discoveries and pursue new exploration opportunities

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2017 FAR Annual Report

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Our mission
Create shareholder value
through exploration
for oil and gas while
operating to industry
best practise standards
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ABOUT US

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FAR Limited is an independent, Africa focussed, Australian Securities Exchange listed, oil and gas exploration and development company with core assets off the coast of Senegal and The Gambia, West Africa, in the emerging MSGBC basin.

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FAR is committed to sustainability and improvement of social, environmental and economic outcomes for the benefit of all stakeholders.

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FAR made the world class, SNE oil discovery off the coast of Senegal in 2014 and has since grown to be one of the largest holders of offshore acreage in the MSGBC basin.

FAR holds 8 exploration permits through Senegal, The Gambia and Guinea-Bissau.

FAR also holds assets in Kenya and Australia.

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2017 FAR Annual Report

2017 HIGHLIGHTS

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End of year cash position
A$49.9M
with no debt
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deepwater The Gambia
w ells drilled
prospective
with 100%
resources
11 success rate
assessed at
The 2017 drilling program included:
1.1 billion bbls
appraisal exploration
3 wells 2 wells
SNE-5 VR-1 SNE-6 SNE North-1 FAN South-1
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Signed Area of Mutual Interest Agreement with CNOOC UK

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March 2017

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FAR Ltd Acreag e Mauritania
Djiffere Permit – Senegal
AMI with CNOOC-Nexen
Farmed into blocks
A2 & A5 The Gambia
March 2017
FAN-1 Rufisque Senegal
Djiffere
Sangomar Offshore
Deep
SNE-1 A2
A5 The Gambia
0 50
km Guinea-Bissau
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Awarded African breakthrough company of the year

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high impact social programs in The Gambia 3

2017 FAR Annual Report 5

CHAIRMAN’S REVIEW

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Fellow shareholders,

It is exciting to be writing this address in early 2018 and reflecting on the activities and achievements of FAR over the last twelve months. We have had another highly successful year in which we completed the third strong drilling campaign and the eleventh successful well offshore Senegal. In doing so, we completed the appraisal of the giant SNE Field and added two more discoveries to FAR’s inventory of oil discoveries offshore Senegal. FAR’s drilling in Senegal has so far seen a 100% success rate. This is quite a remarkable achievement for a country that, only a little over three years ago, had never had a deep-water oil exploration well drilled.

In 2014, the SNE Field was established as the world’s largest oil discovery for the year and FAR has assessed the SNE field to contain 641 million barrels (mmbbls) of oil on a 2C contingent resource basis (gross, unrisked, 96 mmbbls net to FAR).

Having established a significant and growing resource base in the SNE Field through the previous drilling campaigns, the objective of the 2017 appraisal and exploration program was to further define the field for development and drill additional exploration targets that lie within tie-back range of a planned hub development. The well data provided key connectivity and deliverability information from the lower 500 series and upper 400 series sand reservoirs which was the final field appraisal objective. With the completion of these last appraisal wells, detailed planning is now underway for a phased development of the SNE Field.

With the SNE Field on a clear pathway to development, the Exploitation Plan is anticipated to be submitted to the Government of Senegal in the third quarter of this year and approved by the end of 2018. The Final Investment Decision (FID) by the joint venture is planned for mid-2019 and we look forward to sharing the many milestones with our shareholders as we achieve them in the current year. Apart from

the submission of the Exploitation Plan, the joint venture plans to submit an Evaluation Report to the Government of Senegal in mid-2018 which describes the field development concept and associated economics and statement of commerciality. The SNE Field is approximately 350 km[2] in footprint and because of this, the field will be developed in phases, where the first phase will be focused on the core of the field and primarily producing from the 500 series reservoirs which are the deep, thick reservoirs that were flow tested in the first appraisal program at excellent flow rates. Subsequent program will be focused on producing oil from the flanks of the field, tying back the nearby oil discoveries made by the joint venture and potentially producing gas from the field.

Early in 2018, the joint venture agreed the development concept and tenders have been released to the major contractors for the Floating Production and Storage Offtake (FPSO) vessel, drill rigs and subsea infrastructure of the development. A preliminary review of these tender results will be incorporated in to the Evaluation Report to be submitted to the Government of Senegal.

FAR has also continued to focus on the exploration potential around the SNE Field where significant untested prospectivity remains with prolific oil prone source rock, excellent reservoir development and a good working seal. In the 2017 drilling campaign two additional prospects were drilled: FAN South in the deep-water basin and SNE North which lies north of the SNE Field in the shelf edge play. Both wells were discoveries and within tie-back range of the planned development at SNE. Applications have been submitted to the Government of Senegal to appraise these discoveries and work is currently ongoing to integrate the results with existing data to establish the commerciality of the resources.

FAN South-1 encountered hydrocarbon bearing reservoirs and oil samples were obtained with preliminary analysis

indicating 31° API oil quality. SNE North-1 encountered oil and gas in the primary objective and oil in the deeper secondary objective, in a separate accumulation to the SNE field. A full set of oil, water and gas samples were recovered with preliminary analysis indicating a slightly lighter oil type of 35° API. The highquality oil and multiple oil columns not seen in the SNE Field demonstrate that the geology is more complex as we move to the north along the shelf edge play. Following these two additional discoveries, FAR has revised the inventory of undrilled prospectivity offshore Senegal, and whilst there are no plans for drilling these prospects in 2018, they account for considerable upside potential in the acreage that is yet to be realised.

The A2 and A5 exploration blocks offshore The Gambia were captured by FAR in the first quarter of 2017 in a farm-in deal that secured FAR an 80% equity interest and operating rights for the joint venture. This marked a major milestone for FAR as we believe these are potentially the most exciting exploration blocks in the highly prized Mauritania-Senegal-Guinea-BissauConakry (MSGBC) Basin in West Africa and are testimony to FAR’s excellent technical knowledge of the area, Government relationships and commitment to growing the FAR portfolio in this region following the SNE Field discovery.

As I write, we have recently announced bringing our new partner, PETRONAS, the State-owned oil company of Malaysia, into blocks A2 and A5 and carrying FAR through the cost of the first exploration well in country for nearly 40 years. This partnership is important for all joint venture partners and the Government of The Gambia as PETRONAS is a world class deep-water operator that has the capacity to operate the joint venture to first oil should a commercial discovery be made. Under the terms of the agreement, FAR will retain 40% working interest in the joint venture and will be operating the drilling in the joint venture of the first well which is anticipated in the Samo

Prospect in late 2018. The Samo Prospect lies 5kms south of the SNE Field and on a best estimate basis has been assessed by FAR to contain 825 million barrels of oil (P50, gross, unrisked, net 330mmbbls to FAR). As the key oil reservoirs for the Samo Prospect have been drilled with nine wells across the border in Senegal in the discovery and evaluation of the SNE Field, FAR has also forecast the Samo Prospect to have a 50% chance of success.

There is considerable effort being undertaken by the FAR team to be operationally ready to successfully deliver this Samo-1 well. Drilling are expected towards the end of 2018 and results thereafter. Because of the size of the Samo Prospect and the high chance of success, are eagerly anticipated by FAR.

The oil price rout continued throughout 2017 and the capital markets remained tough for FAR throughout the year. We note that this year, as with other years since the fall in the oil price, the cost of drill rigs has been coming down. As I reported last year, in a little over two years since the discovery of SNE, deep water rig rates used in our drilling campaigns have dropped from US$675,000/day to below US$200,000/ day and we look to execute a rig contract for the drilling in The Gambia as soon as possible so as to take advantage of these lower rates. As seen in the 2017 drilling campaign, the drilling has not only been completed at a lower cost but has marked better performance as evidenced by the latter wells in the program that experienced approximately 3% non-productive rig time which is excellent and resulted in all planned wells being completed ahead of time and under budget.

Although the market was largely unyielding for FAR and its oil company peers throughout 2017, there are early signs of a recovery and, as evidenced by the partnership with PETRONAS in The Gambia, larger companies are beginning to look for opportunities for growth. The attractive opportunity that presented itself when our partner in the Senegal joint

venture, ConocoPhillips, agreed to sell its 35% share at a price of approximately US$2.20/bbl of 2C resource to Woodside Energy at a price that was surprisingly low remains more so in today’s market. The sale triggered the rights of partners to pre-empt and, given ConocoPhillips refused FAR access to all the required information to evaluate the opportunity to pre-empt within the allotted timeframe, FAR issued ConocoPhillips with a dispute notice pursuant to the terms of the Joint Operating Agreement. This dispute was not resolved amicably and in June, FAR commenced arbitration proceedings in the International Court of Arbitration to bring the matter to resolution. We have received much shareholder enquiry about the progress of the ICC case and at this time, report that the tribunal is awaiting the appointment of the Chair, after which proceedings can commence. The ICC has a policy of concluding arbitration cases in under 6 months so we are hopeful of resolution before the end of the year and will release material information regarding the case as it comes to light. I am satisfied that we have positioned ourselves comprehensively from a strategic standpoint and feel confident of our position going forward as we seek declaratory relief from the ICC. It is well worth remembering that the outcome of the court process will not affect FAR’s current rights or position.

Thanks to the ongoing support of our shareholders, FAR raised $80M in April and finished the 2017 year with a healthy cash position of $49.9M which will fund us through the budgeted costs of our currently approved programs for 2017. The farmout transaction with PETRONAS will inject additional funds into FAR once Government approval and normal joint venture consent has been received. The bulk of FAR’s expenditure for the year will be on FAR’s share of pre-FEED and FEED activities for Senegal and drill preparations and well costs for the Samo-1 well offshore The Gambia which will be largely paid for by PETRONAS.

FAR has had a strong relationship with the country of Senegal for 12 years and is building a fruitful and hopefully equally strong relationship with our stakeholders in The Gambia. Along with our successful efforts drilling offshore, the company continues to support many social programs in country in its own right and in partnership with joint venture partners. Our primary school renovation projects have been particularly successful, and we look to continue these into 2018. Through these programs we hope to be grounding the next generation of engineers, accountants and environmentalists that will support the growth of the oil industry in the future.

Because of the continued tough market conditions experienced over the year, we continue to tightly manage our costs and although we have had another extraordinarily successful year with the drill bit, the company elected to not award any LTI’s to directors.

We thank our shareholders for continuing to support the company and in particular for supporting our capital raise in April. Once again, the placement was oversubscribed and we have introduced some new, large investors to the register who are committed to the FAR story going forward. I also wish to thank the FAR team for their continued achievements and for being focused on delivering the strategic plan. The team is determined to continue to build on our world class portfolio of opportunities for our shareholders and realise shareholder value in the future.

We look forward to 2018 which we know will be another very busy year for the FAR team. We anticipate that the market will remove the inbuilt price discount for risk around the SNE development plan approval and associated funding risk and that, if successful in the Samo-1 well, it will be a gamechanger for shareholders in FAR. The second half of the year is shaping up to be very exciting for us all.

Nic Limb Chairman

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2017 FAR Annual Report 7

OPERATIONS REVIEW

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SENEGAL

RUFISQUE, SANGOMAR AND SANGOMAR DEEP (RSSD) 16.67% paying interest, 15% beneficial interest Operator: Cairn Energy PLC (‘Cairn’)

Throughout 2017, FAR continued to build its resource base offshore Senegal principally by completing the appraisal drilling over the giant SNE oil field and also by discovering oil in two previously undrilled prospects of FAN South and SNE North.

During the appraisal drilling, the Company achieved several key appraisal milestones and in doing so, progressed the SNE field development project through to the concept select decision. The Exploitation Plan is expected to be delivered to the Minister of Energy in September 2018 with approval for the plan expected before the end of 2018. A Final Investment Decision (FID) is anticipated in mid 2019.

Since the basin opening discoveries of the FAN-1 and SNE-1 wells in 2014, FAR and its Senegalese joint venture partners have successfully drilled a further nine wells in two additional drilling campaigns, resulting in successful appraisal of the SNE field and an additional two oil discoveries which were made in 2017: FAN South-1 and SNE North-1. This totals four oil discoveries and seven successful appraisal wells - there is yet to be a dry well drilled by the joint venture in the RSSD acreage.

The achievements of the highly successful 2016 phase one appraisal drilling and evaluation campaign; which was completed safely, efficiently and under a favourably lower drilling cost environment, delivered outstanding results in which all four wells SNE-2, SNE-3, BEL-1 & SNE-4 encountered an approximate 100m gross oil column. Multiple samples were recovered to surface from drill-stem tests (DST’s) at SNE-2 and SNE-3, with oil sampled from all wells exhibiting similar high-quality 32⁰ API oil. The presence and correlation of principal reservoir units between these four wells across a distance of 9km across the field provided further validation of the lateral connectivity across the SNE oil field.

These outstanding results from the phase one SNE appraisal program delivered two key joint venture objectives. The drilling confirmed the Minimum Economic Field Size (MEFS) of recoverable oil (which FAR estimated to be approximately 200 million barrels) and secondly, determined commercially viable well production rates and reservoir deliverability through a series

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Senegal
Rufisque
SNE North-1
FAN-1 Sangomar Djiffere
BEL-1 Offshore
Sangomar
VR-1 Deep SNE-2
FAN South-1 SNE-1
SNE-3 SNE-4
0 25
SNE-5 SNE-6
km
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FIGURE 1: Senegal location map showing all wells drilled by RSSD JV

of DST’s. The appraisal program also resulted in an increase to the 2C (Best Estimate) Contingent Resources to 641 million barrels (mmbbls) of recoverable oil (100% basis, net 96 mmbbls to FAR). This estimate has been independently audited by RISC Operations Pty Ltd (RISC). Drill stem test flow rates from SNE-2 and SNE-3 exceeded pre-drill expectations and confirmed the excellent deliverability of the lower 500 series reservoir units.

Building upon the success of this first phase appraisal drilling and evaluation campaign, FAR continued its forward momentum into 2017. In November 2016, the Senegal joint venture contracted the Stena DrillMAX, a state-of-the-art 6th generation deepwater drillship, for this second phase of SNE appraisal drilling and evaluation period. A key objective of this program was to determine connectivity of the upper 400 series reservoirs across the field, through an extended well interference test, the results of which would help optimise a future development.

During the first half of the year, FAR successfully and safely completed the second and final phase of its Senegal SNE oil field appraisal program with the drilling and evaluation of the SNE-5, VR-1 and SNE-6 wells, totalling 7 well penetrations on the ‘world-class’ SNE oil field since the SNE-1 discovery well in 2014. As prognosed, each of the three wells encountered an

SENEGAL

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Stena DrillMAX deep
water drill ship
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approximate 100m gross oil column, with the main reservoir units, pressure data and fluid contacts all in line with previous SNE appraisal wells, further confirming the scale and lateral reservoir continuity of the oil field.

Two separate DST’s were conducted at each of wells SNE-5 and SNE-6, as part of a planned interference test to demonstrate reservoir connectivity. Pressure data from the SNE-6 DST immediately confirmed good connectivity with SNE-5 within the upper reservoir units. Both well DST’s exceeded FAR pre-drill expectations and respectively addressed the remaining SNE field appraisal objective of 400 series reservoir connectivity in the field and hence SNE-6 was the last appraisal well to be drilled on the SNE field.

Because of efficiencies in the drilling program, the joint venture agreed to drill a further two wells in the 2017 campaign before releasing the rig. The FAN South-1 well, targeting a southern, deep-water fan complex and the SNE North-1 well, targeting a lookalike prospect to the SNE field on trend to the north of SNE were successfully drilled and both wells were oil discoveries. Both the FAN South and SNE North prospects are within tieback range to a future hub development over the SNE field and these additional barrels are aimed to be produced in the later stages of the phased SNE development.

In events past the end of 2017, the joint venture has agreed the development concept for the SNE field and timetable to submission of the Exploitation Plan for approval on the pathway to achieving FID. The SNE field will be a phased development with the initial phase focusing on the core of the SNE field and development of the thicker, prolific 500 series sands. The development will be via a Floating Production and Storage Offtake Vessel (FPSO) with sub-sea tie backs and tankers transporting the oil to market. The development plan including the final number of wells and volume of oil to be produced in the first and subsequent phases will be finalised through the first half of 2018.

The rapidly emerging MGSBC Basin is increasingly attracting the attention of the world’s oil majors. In March 2017,

FAR announced a strategic partnership with CNOOC UK, underpinned by the execution of an Area of Mutual Interest (AMI) agreement over offshore Senegal and selected licences offshore The Gambia. The agreement positioned FAR to further expand its portfolio and establish itself as one of the key players in this emerging oil ‘hot spot’ of West Africa. FAR continues to work closely with CNOOC UK on opportunities in the area defined in the AMI The RSSD joint venture remains focused on moving the SNE Field to FID in the forthcoming year and no drilling is planned in Senegal for 2018. Table 1 shows a current inventory of contingent and prospective resources in the Senegal acreage, 673 mmbbls are yet to be drilled and remain as potential upside in the permits.

SNE-5 WELL RESULT

The SNE-5 well was the first planned well in the second phase appraisal and evaluation campaign for 2017. SNE-5 was spudded in January 2017 in 1,114m, of water BMSL (below mean sea level) with the key objective of evaluating two principal upper reservoir units, through an oil flow test, predicted to be within the oil leg at this location.

SNE-5 was successfully drilled to a total depth of 2,820m TVDSS (True Vertical Depth Sub-Sea). The well encountered a 100m gross oil column and provided a good correlation of the gross reservoir packages, in particular the upper 400 series reservoirs, with previously drilled SNE wells. Following drilling, the safe completion of logging and DST operations from these upper reservoirs recorded oil flow rates that were in line with or exceeded pre-drill expectations.

The SNE-5 results are consistent with the sand distribution models of the SNE upper reservoirs and give further confidence in the ability to optimally locate and design development wells.

Detailed analysis of the extensive dataset collected from the SNE-5 well is continuing with initial results as follows:

Two drill stem tests (DST) were conducted within the upper reservoirs, confirming confidence in the deliverability of these units.
DST 1a: 18m zone in the S480 reservoir, flowed at a maximum rate 4,500 bopd, stabilized rate 2,500 bopd on 40/64” choke, and 3,000 bopd on 56/64” choke – 24 hour each test. This flow rate was better than the flow rate achieved from the same reservoir in the SNE-3 well.
DST 1b: an additional, a previously untested S460 reservoir section of 8.5m was comingled with the 1a DST to deliver a maximum flow rate 4,200 bopd, average stabilised rate 3,900 bopd on 64/64” choke, above expectations for this interval.
Multiple samples of oil, gas and water were collected from the well which were consistent with samples taken from all other SNE wells.
Depths to the reservoirs, depth to gas oil contact (GOC) and oil water contact (OWC) were on prognosis.

OPERATIONS REVIEW

Confirmation of reservoir quality and correlation of the principal reservoir units.
Oil column thickness confirmed at 100m gross, as seen at all other SNE oil field wells to date.

The material contribution of the upper reservoir units to the SNE oil resource volumes and the ability to produce from the upper reservoir units at commercially viable rates is further support for a potentially very large SNE field development.

Prior to SNE-5 being plugged and abandoned, pressure gauges were installed over the tested reservoir intervals in preparation for the planned SNE-6 well and completion of an interference test.

Incredibly, SNE-5 was completed 21 days ahead of schedule and significantly below budget. As a result of the drilling efficiencies and the need for time to best locate the SNE-6 well for the interference test, the joint venture proceeded to drill the VR-1 well which was not planned at the beginning of the drilling campaign. Efficiencies in drilling meant that the VR-1 well was drilled within the budget for the SNE-5 and SNE-6 wells.

VR-1 WELL RESULT

The VR-1 well is located approximately 5kms west of the SNE-1 discovery well and was drilled with dual objectives; firstly to appraise the upper and lower reservoir units in the western flanks of the SNE field and secondly to investigate the deeper Aptian carbonate exploration targets beneath the SNE oil field. FAR’s depositional model of the upper SNE reservoirs highlighted the potential for additional sand units within the upper reservoir package not previously penetrated by any of the SNE wells to date.

VR-1 was spudded in early March 2017 in 1,379m 2,820 of water and successfully drilled to a preliminary base depth of 2,759m TVDSS where a suite of wireline logging runs and MDT pressure readings confirmed the presence and correlation of reservoir packages across an approximate 100m gross oil column. Fluid contacts and fluid quality were generally in line with results from previous appraisal wells.

FAR’s evaluation of the well results are as follows:

The lower, 500 series 520 reservoir (16m in oil), a key reservoir to the phase 1 development of the SNE field, exhibited excellent reservoir properties, superior to all other reservoirs sampled in the SNE field to date.
The deeper 540 reservoir (11m in oil) has only been seen in the SNE-2 well in oil (2m).
Along with other appraisal wells, the well confirmed a 97m gross oil column with greater than expected net pay and thickest net pay of all appraisal wells drilled to date.

Following the safe logging and sampling of the SNE reservoirs, the well was deepened into the Aptian carbonates to a total depth of 3,867m TVDSS. The deeper carbonate exploration targets

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FAN-1 SNE North-1 BEL-1
SNE-2 SNE-1 SNE-6 SNE-4
VR-1 SNE-3 SNE-5
FAN South-1
GOC
OWC
FIGURE 2:
Location of all
wells drilled to date in
FAR’s Senegal permits
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were penetrated as prognosed, with indications of hydrocarbons, including the evidence of oil, in a secondary target formation described as ‘tight’, which is currently viewed as not being of commercial significance.

The successful VR-1 well was plugged and abandoned according to industry best practices and the rig was then mobilised to the SNE-6 well location.

SNE-6 WELL RESULT

The successful drilling of the SNE-6 well marked the joint venture’s 9th successful well offshore Senegal and the 7th successful appraisal well drilled into the SNE field since the SNE-1 discovery well. The SNE-6 well was spudded in mid-April 2017 in a water depth of ~1,099m BMSL and is located approximately 1.6km north of the SNE-5 well. The key objectives of SNE-6 were to demonstrate reservoir connectivity, as part of an extended interference test, with SNE-5.

The well was completed ahead of schedule and under budget following drilling, logging and drill stem testing of the SNE main upper reservoirs. Pressure data from SNE-6 immediately confirmed good connectivity with SNE-5 and accordingly a short, but highly successful, DST was performed.

The DST produced the following results:

The main reservoir units, pressure data and fluid contacts are in line with previous SNE appraisal wells.
Multiple samples of oil were recovered during the DST and analysis indicates oil of similar quality to previous wells.
Two DSTs were conducted within the upper 400 series reservoir units.

2017 FAR Annual Report 11

SENEGAL

DST#1A flowed from an 11m interval at a maximum rate of ~4,700 barrels of oil per day (bopd) on a 60/64” choke. A 48 hour main flow period was performed at ~3,700 bopd on a 52/64” choke.
For DST#1B an additional 12m zone was added and the well flowed at a maximum rate of ~5,300 bopd on a 64/64” choke, followed by a 24 hour flow at an average rate of ~4,600 bopd on a 52/64” choke.
Pressure data from SNE-6 has confirmed that the upper reservoirs are connected with SNE-5, ~1.6km away.

Excellent flow rates were observed with the SNE-6 DSTs. FAR’s preliminary analysis of the data is consistent with pre-drill geological modelling and indicates that the SNE-5 and SNE-6 wells are sufficiently connected to optimise production of the S480 reservoirs with water flood enhanced recovery techniques.

By achieving connectivity with the SNE-5 well, the SNE-6 well has successfully addressed the remaining key objective of the SNE field appraisal program.

FAN SOUTH-1 WELL RESULT

FAN South-1 was the first well drilled into the deep-water basin offshore Senegal since the initial FAN-1 discovery well in 2014. The South Fan prospect comprises stacked reservoir targets, an Upper Cretaceous stacked multi-layer channelised turbidite fan prospect and a Lower Cretaceous base of slope turbidite fan prospect, similar to the FAN-1 oil discovery.

The FAN South-1 exploration well is located approximately 30km SSW of the FAN-1 well. Drilling reached a total depth of 5,311m TVDSS below a water column of 2,135m (BMSL). The well encountered hydrocarbon bearing reservoirs in the Lower Cretaceous objective before a successful suite of wireline logging and sampling confirmed an oil discovery, with samples of oil being recovered to the surface.

In early 2018, an evaluation plan was submitted to the Minister of Energy for approval. The evaluation plan consisted of a work program to establish the potential commerciality of the FAN South-1 discovery.

SNE NORTH-1 WELL RESULT

The Sirius prospect was the second of two pure exploration plays targeted in the 2017 drilling campaign. The prospect lies immediately north along the structural shelf trend of the world-class SNE oil field and represents a direct analogue of the SNE play type.

The Sirius prospect was targeted with the SNE North-1 well in approximately 877m water depth BMSL. The well spudded in mid-July 2017 before successfully reaching a total depth of 2,805m TVDSS. Operations again were safely and successfully completed ahead of schedule and under budget, following drilling and logging.

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Oil
Gas
Sirius
FAN-1
FAN-1
Sirius
SNE North-1
BEL-1
SNE-2
SNE-1
VR-1
SNE-6
SNE-3
SNE-5 [SNE-4]
FAN South-1
0 5
km
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FIGURE 3: Shelf trend showing SNE-North discovery

SNE North-1 well encountered hydrocarbon bearing zones in three separate intervals, whilst a fourth zone may also be present. These intervals include an oil and gas column in the equivalent high-quality, lower S520 reservoir unit of the SNE field. Pressure data and fluid contact indicates the hydrocarbon column in the S520 reservoir is below the SNE field-wide oil-water-contact and suggests the discovery is a separate accumulation to the SNE field.

FAR’s preliminary analysis indicates:

in excess of 24m of gross hydrocarbon column across at least three intervals.
in excess of 16m of net hydrocarbons in high quality reservoirs.
a lighter oil type of 35° API.

After completing conventional logging, a series of tests were conducted across the reservoir section to further calibrate the geo-mechanical model of the SNE field to assist with the design of development wells.

At the end of 2017, a plan to evaluate the SNE North discovery was submitted to the Minister of Energy for approval. The evaluation plan consisted of a work program to establish the potential commerciality of the SNE North-1 discovery and to integrate the results with the block wide data gathered to date.

OPERATIONS REVIEW

The well result has positive implications for further exploration potential to the north along the structural trend containing the SNE field and, being within tie back range of the planned development of the SNE field, the SNE North oil accumulation is expected to be developed in a later phase of the SNE field development.

The completion of the SNE North-1 well marked the end of the five well drilling campaign for 2017. SNE North-1 was plugged and abandoned as planned, and the Stena DrillMAX rig was released shortly thereafter.

The joint venture has reviewed the potential for further exploration drilling in 2018 and is not planning any drilling in this year – the focus of activities in Senegal is to finalise the development plan and progress to a FID.

DJIFFERE BLOCK OPTION

On 23 September 2015, FAR entered into a farm-in option agreement with TAOL Senegal (Djiffere) Ltd, a subsidiary of Trace Atlantic Oil Ltd (‘Trace’) in which Cap Energy plc holds a 49% participation, for the Djiffere Block offshore Senegal. The Djiffere Block is adjacent to FAR’s highly prospective RSSD Blocks that contain the significant SNE oil field (refer figure 1: Location map FAR Djiffere 3D seismic). FAR acquired a 3D seismic survey over a portion of the block to assess the main prospect, previously

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BEL-1 SNE-2 SNE-1 SNE-4
SNE-6
VR-1 SNE-5
SNE-3
Oil flowlines
Gas injector flowlines NEW VERSION, lines supplied
annotation to come
Water injector flowlines
FPSO mooring chains
Drilling exclusion zone
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FIGURE 4: SNE full field development schematic

mapped on existing 2D seismic data. The new 3D seismic data acquired in late 2015 and final processed products delivered to FAR in early 2017. FAR is currently in discussions with Trace regarding the option to farm into the block.

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Contingent and Prospective Resources []
Low Best High
Senegal Discoveries Estimate Estimate Estimate Probability
and Prospects Play (mmbbls) (mmbbls) (mmbbls) of success (%)
SNE Albian shelf 348 641 1128
FAN Albian basin 30 198 637
Total Contingent
Resources [ (i)] 378 839 1765
Total net to FAR 57 126 265
Spica Albian shelf 58 132 254 32%
Rufisque Albian basin 28 181 849 14%
Leebeer Late cretaceous shelf 68 216 584 33%
Leraw Late cretaceous shelf 24 77 216 18%
Jabbah Late cretaceous shelf 14 35 75 21%
Jabbah Deep Late cretaceous shelf 15 32 67 14%
Total Prospective
Resources 207 673 2045
Total net to FAR 32 101 307
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Table 1: Summary of Senegal contingent and prospective resources

(i) SNE North-1 and FAN South-1 were drilled in 2017. SNE North-1 encountered oil and gas columns, and FAN South-1 discovered oil. The results of these wells are being reviewed and estimates of contingent resources for these discoveries will be made once these studies are completed.

2017 FAR Annual Report

The Gambia

BLOCK A2 and A5 FAR 80% interest and Operator[ (i)] ERIN Energy 20% partner

FAR withstood another year of low oil price environment by focussing on maturing its core Senegal assets and by acquiring new strategic exploration assets to position the company onto a clear path of renewed growth. After the Senegal joint-venture’s ground-breaking discoveries in 2014, the company identified substantial exploration potential in the rapidly emerging MSGBC Basin offshore West Africa where FAR has considerable expertise.

On 28 March 2017, FAR signed a farm-in agreement to expand its exploration portfolio by securing an 80% working interest and operatorship in two highly prospective offshore blocks, A2 and A5, in The Gambia. The assignment was subject to approval by the Government of The Republic of The Gambia which was granted on 3 July 2017.

The farm-in deal with New York and Johannesburg Stock Exchange listed ERIN Energy Corporation requires FAR to fund ERIN up to US$8 million through an exploration well expected to be drilled late in 2018.

Blocks A2 and A5 are adjacent to and on trend with FAR’s giant SNE oil field and have significant exploration potential. The blocks cover an area of approximately 2,682km[2] and lie approximately 30km offshore in water depths ranging from 50 to 1,200m.

During the second half of 2017, FAR completed a detailed geotechnical assessment of the hydrocarbon resource potential in its two blocks offshore The Gambia. From 1,504km[2] of modern 3D seismic data acquired in A2 and A5, FAR identified a number of large prospects similar to the ‘shelf edge’ play which FAR has successfully drilled offshore Senegal. Two drillable prospects, Samo and Bambo as well as other additional leads in the blocks, were identified.

On 27 November 2017, FAR announced the results of an independent resources review conducted by RISC on FAR’s internal estimate of Prospective Resources for two large prospects mapped in permits A2 and A5 (refer figure 6).

The Samo prospect has two target intervals and is on trend and shares many similarities with the giant SNE oil field. As such it is very highly rated with an estimated chance of success (CoS) in one or both targets, endorsed by RISC, of 55%. It is rare to have an exploration prospect with such a high CoS but this reflects the

(i) Before farm-out to PETRONAS in February 2018

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Oil
Gas
Rufisque
RF-1
Senegal
Sangomar
Deep FAN Sangomar
Djiffere
Offshore
SNE
A1 A2 A3
Banjul
A4 A5 A6 The Gambia
0 25 Senegal
km
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FIGURE 5: Location of FAR’s A2 & A5 Blocks in relation to Senegal discoveries

adjacent discovery at SNE and the confidence FAR has developed in exploring in the play fairway which is yet to experience a dry well. The Bambo play type is less understood but the Bambo prospect is still highly regarded with a CoS of 18%. More work will be carried out to improve our understanding of the play and to further derisk the prospect.

The Bambo prospect has been identified following recent mapping of the 3D seismic and targets a separate reservoir objective on the same structural trend as the Samo prospect. The two prospects have a combined best estimate Prospective Resource of 1.1 billion barrels[] on a gross unrisked basis (643 million barrels[] net to FAR) as set out in Table 2. RISC’s report of the assessment of the probabilistic resources confirms it was carried out in accordance with industry standard SPE-PRMS practices.

FAR has also mapped a number of large leads in Block A5. This is in an area of poorer data quality and extends outside the 3D seismic coverage. These leads will be the subject of further mapping definition when the reprocessed seismic data becomes available. The joint venture expects to complete reprocessing and interpretation of the Gambian 3D seismic survey data in the first half of 2018.

TABLE 2: Summary of prospective resources included in RISC’s November 2017 report

Prospective Resources[*]

	Prospectve Resources*
The Gambia Prospects	Low Estmate (mmbbls) P90 Best Estmate (mmbbls) P50 High Estmate (mmbbls) P10
Samo	335 825 1713
Bambo	117 333 902
Total mapped prospects 452 1158 2615
Total net to FAR 363 926 2092

(i) Above figures indicate 80% interest as at end December 2017 prior to farm out of 40% interest in February 2018 to PETRONAS

The Gambia is a material exploration project with billion-barrel oil potential and represents an extension of one of the most attractive exploration target plays in the offshore MSGBC basin since the industry-changing discoveries made by FAR and partners offshore Senegal in 2014. On the 26th February 2018, FAR announced a farm-out deal for blocks A2 and A5 to PETRONAS, the National Oil Company of Malaysia. The agreement with PETRONAS requires PETRONAS to fund 80% of total well costs through an exploration well, Samo-1, up to a maximum total cost of US$45.0 million. FAR is to be paid cash or reimbursement of back costs and consideration, and PETRONAS will also fund FAR’s share of non-well costs up to an agreed amount of US$1.5 million.

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Late Cretaceous Play
Albian Shelf Play
BEL-1 3D Seismic Survey
SNE-2
Sangomar VR-1 SNE-1 Djiffere
Deep SNE-3 Offshore
Sangomar
Senegal
The Gambia
Bambo
Jammah-1
Samo
A1 A2 A3
A4 A5 A6
0 10
km
SNE-6
SNE-4
SNE-5
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FIGURE 6: Block A2 and A5 prospects offshore The Gambia

the exploration phase of the A2/A5 licences, including the drilling of the Samo-1 well, and PETRONAS has a right to become the Operator for development. This farm-out deal with PETRONAS is further recognition of the value of our Gambian licences and FAR’s status as a partner of choice in the Mauritania-SenegalGuinea-Bissau-Conakry Basin.

GUINEA-BISSAU

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0 50 Senegal
km
Guinea-Bissau
1
2
3
4A
4B 5A
6A
5B
7A
6B
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SINAPA (BLOCK 2) AND ESPERANÇA (BLOCKS 4A & 5A) 21.42% paying interest, 21.42% beneficial interest Operator: Svenska Petroleum Exploration AB (‘Svenska’)

The republic of Guinea-Bissau is located on the north west Atlantic margin of Africa. It boasts a functioning hydrocarbon system, good potential reservoirs and multiple drillable prospects in a wide geological setting, including an extension of the shelf edge play extending from southern Senegal, that houses the SNE oil field.

In April 2017, negotiations concluded with the National oil company of Guinea-Bissau, Petroguin, to revise the terms of both the Sinapa and Esperanca Licenses to which FAR has interests. Under the revised license terms, FAR has a 21.42% interest in the permits, an increase from 15% whilst FAR’s paying interest remains at 21.42%.

These changes reflect the fact that Petroguin will no longer have a participating interest in the joint venture prior to a commercial discovery. Upon making a commercial discovery, Petroguin has the right to a participating interest to a maximum of 10% and FAR and Svenska will respectively have interest of 19.28% and 70.71%.

FIGURE 7: Location of FAR’s blocks offshore Guinea-Bissau

Guinea-Bissau, which will now end on 25 November 2020. During this time, the work obligation includes drilling one exploration well on each license with a minimum commitment on each of US$3million (gross). FAR received official confirmation by Government Decree in August 2017.

In addition, the new Licence terms negotiated include more favourable arrangements for deep water investment including reduction to production royalty rates payable to government. The Government also granted a three-year extension to further evaluate the newly acquired 3D seismic data offshore

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further evaluate the newly acquired 3D seismic data offshore
Salt dome
1
Prospect/lead
TABLE 2: Guinea-Bissau project contingent and prospective resources [] 3D Surveys 2001-2010
3D Survey 2015
Contingent & Prospective Resources []
Low Best High
Guinea-Bissau Estimate Estimate Estimate Atum 2
Prospect (mmbbls) (mmbbls) (mmbbls)
Sinapa
Sinapa Discovery 4.4 13.4 38.9 Sabayon West Sinapa
East
Anchova
Total Contingent 4.4 13.4 38.9
Arinca
Total net to FAR 0.9 2.9 1.2 N. Solha
NW. Solha
4A
East Sinapa 1.8 7.5 34.2 S. Solha
West Sinapa 17.7 34.7 251.7
Atum 144 471.7 1,569.6 4B
North Solha 6 28.4 131.6
5A
Arinca 10 59.2 393
Sabayon 3.4 18.1 88.2
Other leads 85.4 303.7 1,032 6A
5B
Total Prospective 269 954 3,500 0 20
6B km
Total net to FAR 57 204 112
FIGURE 8: Block 2 & Blocks 4A/5A prospects, offshore Guinea-Bissau
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FIGURE 8: Block 2 & Blocks 4A/5A prospects, offshore Guinea-Bissau

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KENYA

BLOCK L6

Onshore 24% paying and beneficial interest Offshore 60% paying and beneficial interest Operator: FAR Ltd

The L6 permit area in the Lamu Basin covers over 3,134km² with about one quarter onshore and the remaining offshore in water depths up to approximately 400m. FAR’s initial strategic interest was on the onshore exploration play which should there be a discovery could be readily commercialised.

The largest potential prospect identified to date is the Kifaru prospect in water depths of 80-100m in the southwest of the L6 permit. This prospect and several others have been covered by a 3D seismic survey (refer Table 3). Block L6 has the potential to contain approximately 3.7 billion barrels of oil or 10.2 trillion cubic feet of gas prospective resources on a gross, un-risked, best estimate basis, as assessed by FAR and audited by RISC.

FAR’s intends to discuss with its partner in the L6 joint venture (Pancontinental Oil and Gas Limited: PCL) on future of exploration plans for the block.

No technical work was completed in 2017 on approved work program due to continued land access issues. In the interim the Ministry of Energy and Petroleum have consented to a non-operations extension of the permit and is in dialogue with FAR amicably to resolve the same.

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L1A
Kenya L1B
L2 L3
L13
L4
L14
L5
L22
L20 L6 L7
L15
L16 L8 L12 L25
L19
L17 L9
L11A L27
L10A
L11B L28
L18 L10B
0 100
km
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FIGURE 9: Location of FAR’s L6 Block offshore Kenya

TABLE 3: Estimate of Prospective Resources[] for Block L6, Kenya Prospective*

FIGURE 10: Leads and prospects mapped offshore Kenya

pp pp y	pp pp y	pp pp y	pp pp y				Resources*
L6 Mbawa Discovery Sunbird Discovery Kifaru Miocene Reefs Miocene Fans Eocene Clastcs Cretaceous Clastcs Other leads & prospects Gas discovery Oil & Gas discovery Eocene Oil Kitchen Kifaru 3D Survey Kenya							Best Estmate (mmbbls)

				OFFSHORE

				Kifaru Miocene Reef P		lay	178
				K~~i~~faru West Miocene Reef P		lay	130
				Tembo Eocene Clastic		s Play	327
				Kiboko Eocene Clastic		s Play	110
				Nyat Eocene Clastic		s Play	149
			Mbawa Discovery	Nyat
				Nyat	West Eocene Clastic	s Play	304
				Chui	Eocene Clastic	s Play	188
				Chui	West Eocene Clastic	s Play	77
				Othe	r Eocene Clastcs Play		769
				Othe	r Miocene Reef Play		1,249
				Late	Cretaceous Clastcs Play		95
	Sunbird Discovery
				Total	ofshore prospects		3,577

				Total –~~of~~	net to FAR shore prospects		2,146
		Sunbird Discovery
				ONS	HORE
				Mam	ba Eocene Clastic	s Play	31
				Kudu Eocene Clastic		s Play	115

				Other Late Cretaceous Clastcs Play			31
				Total onshore prospects			177
				Total net to FAR – onshore prospects			43
				Total all prospects			3,754
				Total all prospects – net to FAR			2,189

AUSTRALIA

Surrounded by proven petroleum systems

Unlocking the exploration potential and hydrocarbon prospectivity of WA-458-P.

WESTERN AUSTRALIA

WA-458-P OFFSHORE DAMPIER BASIN 100% paying and beneficial interest Operator: FAR Ltd

WA-457-P OFFSHORE DAMPIER BASIN 100% paying and beneficial interest Operator: FAR Ltd

FAR participated in the Davros multi-client 3D seismic survey acquired over a large area of the north-west shelf of Western Australia and planned to completely cover both FAR permits, WA-457-P and WA-458-P. Due to environmental restrictions to the data acquisition, only 62% of the WA-458-P permit has been covered by 3D seismic data.

As a result of the ongoing process of securing environmental approvals to acquire the data, FAR was granted a 24 month extension to the permit term which was granted in late 2017. Permit years 2, 3 and 4 (current permit period) will now end on 6 July 2019.

TABLE 4: Estimate of Prospective Resources[*] for Block WA-458-P

Atli	Prospectve Resources*
usraa Prospects	Best Estmate(mmbbls)
WA-458-P
Top Angel Play	20.7
Lower Angel Structural Play	5.8
Lower Angel Stratgraphic Play	152.2
Oxfordian Fan Play	126.8
Legendre Structural Play	53.4
Total all prospects	358.9
Total net to FAR	358.9

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Oil field
Gas field Mutineer/PitcairnFletcher
Davros MC3D
Davros MC3D Extension Exeter Finucane
Perseus EaglehawkEgret LambertHermes WA-458-P Talisman
MontagueAngel Amulet
North Cossack
Keast/DockrellGoodwyn GaeaRankin Wanaea Ajax
Hurricane Legendre
Echo/
Yodel Tidepole
Dixon
Sculptor WA-457-P Sage
Saffron
Wilcox
Corvus ReindeerUnicornGungurru
Wandoo
Tusk
Oryx Stag
0 20
km
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FIGURE 11: Location of Blocks WA-458-P, offshore Western Australia

During this period, FAR will complete the 3D seismic survey over the WA-458-P (in events post the end of the year, FAR has been advised that environmental approval has been granted for a modified seismic acquisition program and discussions are in progress to finalise a timetable for the survey to be acquired).

Following the success of FAR’s Senegal program and its farm-out to PETRONAS in The Gambia, FAR intends to farm-down its high interest in WA-458-P after acquisition of this 3D survey.

FAR submitted a request to surrender the WA-457-P permit in late 2016 and that process is ongoing. FAR remains in communication with NOPTA (Australian National Offshore Petroleum Titles Administrator) regarding the surrender and intends to leave the permit in good standing.

2017 FAR Annual Report 19

CORPORATE ACTIVITY

EXPLORATION ASSETS

At the end of the financial year FAR had a robust cash position with combined cash and long term deposits of AU$49.9m. In April 2017, FAR successfully completed a fully underwritten placement to institutional and sophisticated investors to raise AU$80 million through a placement of fully paid ordinary shares. The placement was significantly oversubscribed with strong support by existing shareholders, and it also saw the introduction of new institutional investors to FAR’s register. Proceeds from the placement are to be used to fund FAR’s continued participation in the 2017 and 2018 drilling, evaluation and pre-development program offshore Senegal, to complete the acquisition of Blocks A2 and A5 in The Gambia and undertake 3D seismic reprocessing and interpretation and general corporate purposes. FAR holds the majority of its cash in US$’s – the currency in which the substantial majority of costs are incurred.

FAR holds a wide portfolio of exploration licenses across 11 Blocks and permits in Africa and Australia.

The core focus area for the company is Africa, and specifically West Africa after making the basin opening FAN-1 and SNE-1 oil discoveries in 2014. FAR has now completed a 9 well drilling program offshore Senegal and has now completed the appraisal process for the world class SNE field along with making two further discoveries in FAN South-1 and SNE North-1.

FAR also farmed in to 2 Blocks offshore The Gambia which are adjacent to and on trend with FAR’s giant SNE field. Guinea-Bissau and Kenya represent FAR’s other African assets.

As at the end of 2017, the Company assets are tabled below.

	Project	Asset FAR Paying Interest Benefcial Interest Operator
	Senegal	Rufsque, Sangomar and Sangomar Deep 16.7% 15.0% Cairn Energy
	The Gambia	Block A2 and A5 80%(i) 80%(i) FAR
	Guinea-Bissau	Block 2, 4A, 5A 21.42% 21.42% Svenska
	Kenya	Block L6 (ofshore) 60% 60% FAR
		Block L6 (onshore) 24% 24% FAR
	Australia	WA-458-P 100% 100% FAR
		WA-457-P 100% 100% FAR

(i) Before farm-out to PETRONAS in February 2018

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20
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*Disclaimers

Prospective Resource Estimates Cautionary Statement – With respect to the prospective resource estimates contained within this report, it should be noted that the estimated quantities of Petroleum that may potentially be recovered by the future application of a development project may relate to undiscovered accumulations. These estimates have an associated risk of discovery and risk of development. Further exploration and appraisal is required to determine the existence of a significant quantity of potentially moveable hydrocarbons.

Prospective Resources – All contingent and prospective resource estimates presented in this report are prepared as at 27/2/2013, 11/3/2014, 5/2/2014, 13/04/2015, 13/4/2016, 23/08/2016, 7/2/2017 and 21/11/2017 (Reference: FAR ASX releases of the same dates). The estimates have been prepared by the Company in accordance with the definitions and guidelines set forth in the Petroleum Resources Management System, 2007 approved by the Society of Petroleum Engineer and have been prepared using probabilistic methods. The contingent resource estimates provided in this report are those quantities of petroleum to be potentially recoverable from known accumulations, but the project is not considered mature enough for commercial development due to one or more contingencies. The prospective please confirm if updated in resource estimates provided in this report are Best Estimates and represent that there is a 50% v3? probability that the actual resource volume will be in excess of the amounts reported. The estimates are unrisked and have not been adjusted for both an associated chance of discovery and a chance of development. The 100% basis and net to FAR contingent and prospective resource estimates include Government share of production applicable under the Production Sharing Contract.

Competent Person Statement Information –The hydrocarbon resource estimates in this report have been compiled by Peter Nicholls, the FAR Limited exploration manager. Mr Nicholls has over 30 years of experience in petroleum geophysics and geology and is a member of the American Association of Petroleum Geology, the Society of Petroleum Engineers and the Petroleum Exploration Society of Australia. Mr Nicholls consents to the inclusion of the information in this report relating to hydrocarbon Contingent and Prospective Resources in the form and context in which it appears. The Contingent and Prospective Resource estimates contained in this report are in accordance with the standard definitions set out by the Society of Petroleum Engineers, Petroleum Resource Management System.

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Forward looking statements – This document may include forward looking statements. Forward looking statements include, are not necessarily limited to, statements concerning FAR’s planned operation program and other statements that are not historic facts. When used in this document, the words such as ‘could’, ‘plan’, ‘estimate’, ‘expect’, ‘intend’, ‘may’, ‘potential’, ‘should’ and similar expressions are forward looking statements. Although FAR Ltd believes its expectations reflected in these are reasonable, such statements involve risks and uncertainties, and no assurance can be given that actual results will be consistent with these forward looking statements. The entity confirms that it is not aware of any new information or data that materially affects the information included in this announcement and that all material assumptions and technical parameters underpinning this announcement continue to apply and have not materially changed.

*Notes to Prospective Resources Estimates

The estimated quantities of Prospective Resources stated throughout the report may potentially be recovered by the application of a future development project(s) relate to undiscovered accumulations. These estimates have both an associated risk of discovery and a risk of development. Further exploration appraisal and evaluation is required to determine the existence of a significant quantity of potentially moveable hydrocarbons.
The recoverable hydrocarbon volume estimates prepared by the company and stated in the tables throughout the report have been prepared in accordance with the definitions and guidelines set forth in the Petroleum Resources Management System, 2007 and 2011 approved by the Society of Petroleum Engineers.
The Prospective resource estimates have been estimated using deterministic methods using best estimates of all parameters.
The barrel of oil equivalent (BOE) is a unit of energy based on the approximate energy released by burning one barrel (42 U.S. gallons or 158.9873 litres) of crude. One BOE is roughly equivalent to 5,800 cubic feet (164 cubic meters) of typical natural gas, which is the conversion used in this analysis to calculate BOE for the gas volumes. The value is necessarily approximate as various grades of oil and gas have slightly different heating values.
The Best Estimates reported represent that there is a 50% probability that the actual resource volume will be in excess of the amounts reported.
The estimates for unrisked Prospective Resources have not been adjusted for both an associated chance of discovery and a chance of development.
The chance of development is the chance that once discovered, an accumulation will be commercially developed.
Prospective Resources means those quantities of petroleum which are estimated, as of a given date to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.
In the table, the abbreviation ‘mmbbls’ means millions of barrels of oil or condensate and ‘bcf’ means billions of cubic feet of gas.

2017 FAR Annual Report

GOVERNANCE AND SUSTAINABILITY

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Corporate Governance

Australian Securities Exchange Listing Rule 4.10.3 requires companies to disclose the extent to which they have complied with the best practice recommendations of the ASX Corporate Governance Council.

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FAR Limited’s objective is to achieve best practice in corporate governance commensurate with FAR’s size, its operations and the industry within which it participates.

Charters

Board Audit Committee Nomination Committee Remuneration Committee Risk Committee

FAR’s policies and charters can be found on our website and are listed to the right.

Policies

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Anti-Bribery & Corruption Code of Conduct Diversity Environment & Sustainability Human Rights & Child Protection Market Disclosure & Communications Risk Oversight & Management Security Trading & Policy Statement

FAR publishes its Corporate Governance Statement on its website rather than in its annual report. Our 2017 Corporate Governance Statement can be viewed on our website at www.far.com.au/governancesocial-responsibility/.

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Transparency

FAR Limited commits to actively working with the governments, national organisations, companies, media and financial institutions within the countries it operates to support, promote and participate in programs that encourage transparency and international best practice for governance.

FAR’s corporate focus is investing in African exploration and development projects for oil and gas with its core project in Senegal. FAR recognises that the countries within which we operate are often immature in their development and application of transparency policy and hence FAR strives to support this development to ensure positive foreign investment, infrastructure and capacity building and economic growth.

FAR is a member of the Extractive Industries Transparency Initiative (EITI), along with the Government of Senegal. Further information about the EITI can be found at their website www.eiti.org

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Environment

FAR is committed to achieving excellence in managing its environmental, safety, health and social performance in all of our work places, activities and operations.

It is acknowledged that, to be most effective and to achieve long term success, this should become part of the culture of the organisation, embedded into FAR’s philosophy, practices and business processes. To meet these objectives, FAR seeks to:

protect the health, safety and wellbeing of our staff, contractors and the local communities our operations impact upon;
manage and maintain positive and respectful relationships with the communities with which we conduct business and in which we operate, including encouraging and supporting their economic prosperity;
manage safety and environmental risk , ensuring that all material risks are identified, objectively assessed, monitored and responded to in an appropriate manner;

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maintain a high standard of care for the natural environment and adopting appropriate environment management systems on our contract areas ; and
reduce our environmental footprint by efficient use of resources, management of water and energy consumption and management of waste and emissions.

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Community and social programs

FAR directly supported the following activities in 2017:

The Tallinding Project school renovation – Serrakunda, The Gambia
Donation of 100 rubbish bins to multiple markets in Serrakunda, The Gambia
Provision of soccer balls to 10 football groups including female groups in The Gambia

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2017 FAR Annual Report 23

DIRECTORS’ REPORT

The directors of FAR Ltd submit herewith the Annual Financial Report for the year ended 31 December 2017. In order to comply with the provisions of the Corporations Act 2001, the Directors’ Report as follows:

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INFORMATION ABOUT THE DIRECTORS

The directors of the Company in office during or since the end of the financial year are:

Nicholas James Limb – Non-Executive Chairman Bsc (Hons) MAusIMM (appointed 28 November 2011)

Mr Limb is a professional geophysicist and has extensive experience in the management of resource companies. Additonally, he has a considerable background in capital markets having worked in investment banking for approximately 10 years. He is currently Non-executive Chairman of Mineral Deposits Limited, an Australian listed company. Mr Limb was appointed as Chair on 19 April 2012. He is Chair of the nomnation committee and a member of the remuneration and audit committees.

Catherine Margaret Norman – Managing Director Bsc (Geophysics) (appointed 28 November 2011)

Ms Norman is a professional geophysicist who has over 30 years experience in the minerals and oil and gas exploration industry, having held executive positions both in Australia and the UK and carried out operating assignments in Europe, Africa, the Middle East and Australia. Ms Norman served as Managing Director of Flow Energy Limited from 2005 and was appointed Managing Director of FAR Limited on 28 November 2011.

Benedict James Murray Clube – Executive Director and Chief

Operating Officer Bsc (Hons) Geology, ACA (appointed 12 April 2013)

Mr Clube has over 30 years experience in the oil and gas industry. He was the Vice President of Finance and Planning at BHPBilliton Petroleum and held a number of other senior executive positions at BHPBilliton Petroleum based in Houston, London, Perth and Melbourne and was a director of a number of BHPBilliton companies. Following his time at BHPBilliton, Mr Clube was Finance Director and Company Secretary of Oilex Ltd, an Australian and AIM listed petroleum company.

Reginald George Nelson – Non-Executive Director

BSc, Hon Life Member Society of Exploration Geophyscists, FAusIMM, FAICD (appointed 9 April 2015)

Mr Nelson is an exploration geophysicist with over 50 years of experience in the petroleum and minerals industries and has served as a director of various ASX listed companies for 25 years. He held the positions of Managing Director/CEO of Beach Energy Limited from 1995 to 2015. He is a former Chairman of the Australian Petroleum Production and Exploration Association (APPEA) and is a recipient of APPEA’s Reg Sprigg Gold Medal award for outstanding services to the Australian oil and gas industry. He was appointed by the Premier of South Australia as Chairman of the South Australian Minerals and Petroleum Expert Group (SAMPEG) in December 2016. Mr Nelson is Lead Independent Director, Chair of the nomnation committee and a member of the remuneration and audit committees.

Timothy Roy Woodall – Non-Executive Director BEc, FCPA, GAICD (appointed 1 August 2017)

Mr Woodall has over 25 years’ experience in international M&A and finance, specialising in the oil and gas sector. His expertise includes being the founder and Managing Director of a boutique advisory firm, the CEO of an international technical consulting firm and senior roles in New York and London with global investment banks. Additionally, he has held senior executive positions with E&P companies in Australia and the USA. Mr Woodall is a non-executive director of Central Petroleum Limited, an Australian listed company. He is Chair of FAR’s audit committee and a member of the nomination and remuneration committee.

Albert Edward Brindal – Non-Executive Director BCom, MBA, FCPA (Retired 29 May 2017)

Mr Brindal holds a Bachelor of Commerce Degree, an MBA and is a Fellow of the Certified Practicing Accountants in Australia. Mr Brindal has previously served as Company Secretary from 26 April 2000 until 4 April 2013. He was also a member of the nomination, remuneration and audit committees.

DIRECTORSHIPS OF OTHER LISTED COMPANIES

Directorships of other listed companies held by directors in the 3 years immediately before the end of the financial year are as follows:

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|---|---|---|
|Name|Company|Period of|
|directorship|
|N J Limb|Mineral Deposits|Since 1994|
|Limited|
|World Titanium|From October 2013|
|Resources Limited|– May 2016|
|R G Nelson|Beach Energy Ltd|From May 1992|
|– March 2015|
|T R Woodall|Central Petroleum|Since December 2017|
|Limited|

----- End of picture text -----

DIRECTORS’ SHAREHOLDINGS

The following table sets out each director’s relevant interest in shares, options and performance rights over shares of the Company at the date of this report:

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----- Start of picture text -----

|||||
|---|---|---|---|
|Shares|Options|Performance|
|Rights|
|N J Limb|39,908,139|-|-|
|C M Norman|18,674,090|10,000,000|3,578,000|
|B J M Clube|23,732,000|8,000,000|3,090,000|
|R G Nelson|500,000|5,000,000|-|
|T R Woodall|2,000,000|-|-|

----- End of picture text -----

REMUNERATION OF KEY MANAGEMENT PERSONNEL

Information about the remuneration of key management personnel (KMP) is set out in the remuneration report section of this directors’ report. The ‘key management personnel’ refers to those persons having authority and responsibility for planning, directing and controlling the activities of the consolidated entity, directly or indirectly, including any director (whether executive or otherwise) of the consolidated entity.

SHARE OPTIONS AND PERFORMANCE RIGHTS GRANTED TO DIRECTORS AND SENIOR MANAGEMENT

During and since the end of the financial year 5,159,000 performance rights were granted to senior management of the company as part of their remuneration. No Performance rights were granted to directors during the year. No options were granted during or since the end of the financial year.

PRINCIPAL ACTIVITIES

The principal activities of the Company and of the Group during the course of the financial year were:

Conducting exploration for oil and gas deposits;
Conducting activities to identify and evaluate new exploration projects; and
Monetisation of oil exploration and production interests.

There were no significant changes in the nature of these activities during the year.

OPERATING RESULTS

The net loss of the Group for the year ended 31 December 2017 after income tax was $42,779,180 (2016: $21,759,974).

DIVIDENDS

COMPANY SECRETARY

Peter Anthony Thiessen B.Bus, CA (appointed 20 August 2012)

Mr Thiessen, Chartered Accountant, held the position of company secretary of FAR Ltd at the end of the financial year. He joined FAR Ltd in 2012 and also serves as the Chief Financial Officer of the Group.

The directors recommend that no dividend be paid for the year ended 31 December 2017 nor have any been paid or declared during the year.

REVIEW OF OPERATIONS

A review of the operations of the Company and the Group is set out in the Operations Review section of this Annual Report.

Results for the year

	FY17 $ FY16 $ Change %
Proft & loss
Revenue	614,149 165,777 270%
Expenses	(43,393,329) (21,925,751) 98%
Loss for the period	(42,779,180) (21,759,974) 97%
Basic EPS (cents)	(0.83) (0.52)
Financial positon
Net assets	171,587,571 144,800,225 18%
Cash balance	49,926,796 46,978,179 6%
Cash fows
Operatng cash fow	(35,262,140) (20,773,529) 70%
Investng cash fow	(34,844,794) (53,709,928) (35%)
Financing cash fow	76,587,542 60,127,254 27%

The group reported loss for the 2017 year of $42,779,180 is 97% greater than the prior year loss of $21,759,974. This is principally due to higher exploration expenses of $35,200,227 (2016: $16,352,405) and a foreign exchange loss of $3,367,979 compared with a gain of $767,004 in the prior year. The increase in exploration expenses relate primarily to the Senegal drilling campaign and expensing of exploration drilling costs, pre development planning costs and the acquisition of seismic in The Gambia. Partly offsetting the increased exploration expenses was a reduction in employee benefit expenses of close to 30% ($1,345,685 lower) due to lower non cash share based payments of $446,169 compared with $2,490,223 in the prior year.

Financial position

The Group’s balance sheet was strengthened during the year by a capital raising of $80,000,000 before costs received in two tranches at a share price of 8.0 cents per share. The first tranche unconditional proceeds were received in April and the balance in May subsequent to shareholder approval.

Net assets increased during the year by 18% to $171,587,571 (2016: $144,800,225). This is due predominantly to the increase in exploration and evaluation assets of $27,027,878 to $128,734,644 resulting from the capitalisation of the Senegal SNE-5, VR-1, SNE-6, and SNE North-1 well costs and The Gambia farm-in costs, well planning and drilling long lead items. Trade and other payables increased by $2,610,991 to $8,569,700 during the

2017 FAR Annual Report 25

year mainly due to higher Senegal non well related costs at year end compared with the prior year.

The cash balance at the end of the year of $49,926,796 was slightly higher than the prior year of $46,978,179. The main movements in cash during the year were $35,262,140 cash outflow from operations comprising of $30,800,533 in payments for exploration and evaluation expensed, cash outflows from investing of $34,844,794 including $28,206,395 in payments for exploration and evaluation capitalised and $7,109,497 for the payment of The Gambia farm-in costs, net cash proceeds from financing of $76,587,542 from the issue of shares and a $3,531,991 negative effect on cash due to exchange rate changes.

As at 31 December 2017 the Group had no borrowings or undrawn financing facilities. The Company continues to actively identify and develop funding options in order to meet its expenditure commitments (see Note 16) and its planned future discretionary expenditure.

The Group’s cash position and financial management is reviewed on a regular basis by the Company’s Executive Management and is reported to the Board on a regular basis. The Group’s Chief Financial Officer is responsible for ensuring the Board has adequate information on the Group’s cash position and financial forecasts for determining whether the Group is able to meet its financial obligations as and when they fall due.

Business Strategy and prospects

The Company is currently focused on oil and gas exploration and appraisal in Africa and Australia. The Company continues to progress its current portfolio of projects and assess new oil and gas exploration opportunities principally in Africa to grow its pipeline of projects. The Company’s strategy is to identify and secure high potential exploration licences and permits at an early stage in the exploration cycle and add value and mitigate technical, operational and financial risks through prioritising and diversifying its exploration, appraisal and development activities and entering commercial arrangements including farm-outs and sale and purchase transactions. During the year the Company continued to explore and evaluate its current portfolio of projects. In Senegal the Company continued appraisal activities of the SNE field. The Company also identified and assessed new oil and gas exploration opportunities within Africa, Australia and elsewhere to grow its portfolio of projects.

MATERIAL BUSINESS RISKS

The international scope of the Group’s operations, the nature of the oil and gas industry and external economic factors mean that a range of factors may impact results. Material macro-economic risks that could impact the Company’s results and performance include oil and gas commodity prices, exchange rates and global factors effecting capital markets and the availability of financing. Material business risks that could impact the Company’s performance are described the following paragraphs.

TECHNICAL AND OPERATIONAL RISKS

Exploration

Oil and Gas exploration is speculative by nature and therefore carries a degree of risk associated with the discovery of hydrocarbons in commercial quantities. Exploration activity may be adversely influenced by a number of different factors including, amongst other things, new subsurface geological and geophysical data, drilling results including the presence,

prevalence and composition of hydrocarbons, force majeure circumstances, drilling cost overruns for unforeseen subsurface operating conditions or unplanned events or equipment difficulties, changes to resource estimates, lack of availability of drill rigs, seismic vessels and other integral exploration equipment and services.

Other operational risks

In addition to the material risks listed, the Group’s operations are potentially subject to other industry operating risks including fire, explosions, blow outs, pipe failures, abnormally pressured formations and environmental hazards such as accidental spills or leakage of petroleum liquids, gas leaks, ruptures or discharge of toxic gases. The occurrence of any of these risks could result in substantial losses to the Group due to injury or loss of life; damage to or destruction of property, natural resources, or equipment; pollution or other environmental damage; cleanup responsibilities; regulatory investigation and penalties or suspension of operations. Damages occurring to third parties as a result of such risks may also give rise to claims against the Group.

The Group manages operational risk through a variety of means including selecting suitably experienced qualified Joint arrangement partners and operators, regular monitoring of the performance of operators in accordance with the Group’s policies; recruitment and retention of appropriately qualified employees and contractors, establishment and use of Group-wide risk management system. In addition, the Group implements insurance programs in place and specific insurance policies in relation to drilling operations that are consistent with good industry practice.

JOINT OPERATION RISK

The use of joint operation are common in the oil and gas industry and usually exist through all stages of the oil and gas life cycle. Joint operation arrangements, amongst other things, mainly serve to mitigate the risk associated with exploration success and capital intensive development phases. However, failure to establish alignment between joint operation participants, poor performance of third party joint operation operators or the failure of joint operation partners to meet their commitments and share of costs and liabilities could have a material impact on the Group’s business.

The Group manages joint operation risk through careful joint operation partner selection (when applicable) stakeholder engagement and relationship management. Commercial and legal agreements are also in place across all joint operations and define the responsibilities and obligations of the joint operation parties and rights of the Group.

GOVERNMENT AND REGULATOR RISK

The Group’s rights, obligations and commercial arrangements through all stages of the oil and gas lifecycle (exploration, development, production) in international oil and gas permits are commonly defined in agreements entered into with the relevant country’s Government as well as in the Country’s petroleum and tax related legislation and other laws. These agreements and laws are at risk of amendment by future Governments which accordingly could materially impact on the Group’s rights and commercial arrangements adversely. Further, due to the evolving nature of exploration work programs (as new technical data) becomes available and due to the fluctuating availability of petroleum equipment and services, the Group may seek to

DIRECTORS’ REPORT

negotiate variations to permit agreements in particular, in relation to the duration of the exploration phase in the permit and the work program commitments.

The Group manages Government and Regulator risk through careful Government and regulator relationship management. Failure to maintain mutually acceptable arrangements between the Group and Government and regulator could have a material impact on the Group’s business including forfeit or relinquishment of permits or commercially less advantageous terms being imposed on permits.

SOVEREIGN RISK

The Group strategy is focused on exploration in Africa. Some countries within which the Group operates are developing countries that have political and regulatory structures which are maturing and have potential for further change. Uncertainty exists as to the stability of the regulatory and political environment and there is potential for events to have a material impact on the investment and security environment within the country. The Group manages sovereign risk through closely monitoring political developments and events in country. The Group manages and amends its investment profile within a country by taking into consideration developments in the security and business environment.

ENVIRONMENTAL RISKS

Oil and gas operations have inherent risks and liabilities associated with ensuring operations are carried out in a manner that is responsible to the environment. Although the Group operates within the prevailing environmental laws and regulations, such laws and regulations are continually changing and as such, the Group could be subject to changing obligations or unanticipated environmental incidents that, as a result, could impact costs, provisions and other facets of the Group’s operations.

The Group complies with all environmental laws and regulations and, where laws and regulations do not exist, it aims to operate at the highest industry standard for environmental compliance. The Group identifies risks, threats, hazards and other environmental considerations and implements control measures to mitigate such risks. Any accidents, incidents or near misses are reported to the Board. Careful selection and engagement of contractors is undertaken to ensure adherence to the Group’s policies and appropriate contingency arrangements are put in place which include but are not limited to having insurances in place that are consistent with good industry practice; and, selection and retention of appropriately qualified personnel.

CHANGES IN STATE OF AFFAIRS

Senegal

Buildng upon the success of the Senegal first phase drilling and evaluation campaign in 2016, FAR continued that momentum through 2017 to complete the appraisal process of the world class SNE field. In November 2016, the Senegal joint venture contracted the Stena DRILLMAX, a state fo the art 6th generation deepwater drillship, for the second phase of the SNE appraisal program. During the first half of 2017, FAR successfully and safely completed the second and final phase of its Senegal SNE oil field appraisal program with the drilling and evaluation of the SNE-5, VR-1 and SNE-6 wells, bringing the total to 7 well penetrations on the world class SNE oil field since the SNE-1 discovery well in 2014.

In January 2017, drilling begun on the first well planned in the second phase appraisal and evaluation campaign for 2017 at SNE-5. On the 8th March 2017, FAR announced the SNE-5 well had been successfully drilled, logged and flow tested 21 days ahead of schedule and significantly below budget. The well encountered a 100m gross oil column and provided a good correlation of the gross reservoir packages, in particular the upper 400 series reservoirs, with previously drilled SNE wells. Following drilling, the safe completion of logging and DST operations from these upper reservoir units recorded oil flow rates that were in line with or exceeded pre-drill expectations. As a result of the drilling efficiencies and the need for time to best locate the SNE-6 well for the interference test, the joint venture proceeded to drill the VR-1 well which was drilled within budget for the SNE-5 and SNE-6 wells.

On 27th March 2017, FAR announced successful completion of the VR-1 well. FAR’s evaluation of the well results were as follows. The lower, 500 series 520 reservoir (16m in oil), a key reservoir to the phase 1 development of the SNE field, exhibited excellent reservoir properties, superior to all other reservoirs sampled in the SNE field to date. The deeper 540 reservoir (11m in oil) has only been seen in the SNE-2 well in oil (2m). Along with other appraisal wells, the well confirmed a 97m gross oil column with greater than expected net pay and thickest net pay of all appraisal wells drilled to date. The successful VR-1 well was plugged and abandoned according to industry best practises and the rig was mobilised to the SNE-6 well location.

On 18th May 2017, FAR announced the successful connectivity result of the SNE-6 appraisal well. Two separate DST’s were conducted at each of wells SNE-5 and SNE-6, as part of a planned interference test to demonstrate reservoir connectivity. Pressure data from the SNE-6 DST immediately confirmed good connectivity with SNE-5 within the upper reservoir units. Both well DST’s exceeded FAR pre-drill expectations and respectively addressed the remaining SNE field appraisal objective of 400 series reservoir connectivity in the field and hence SNE-6 was the last appraisal well to be drilled on the SNE field. By achieving connectivity with the SNE-5 well, the SNE-6 well had successfully addressed the remaining key objectives of the SNE field appraisal program.

Because of efficiencies in the drilling program, the joint venture agreed to drill a further two wells in the 2017 campaign before releasing the rig. The FAN South-1 well, targeting a southern, deepwater fan complex and the SNE North-1 well, targeting a lookalike prospect to the SNE field on trend to the north of SNE were successfully drilled and both wells were oil discoveries. Both the FAN South and SNE North prospects are within tieback range to a future hub development over the SNE field and these additional barrels are aimed to be produced in the later stages of the phased SNE development. At year end, the focus moved to finalising the development plan and progressing to FID of the SNE oil field.

The Gambia

In March 2017, FAR announced it had expanded its West African portfolio by acquiring 80% working interest and Operatorship in the highly prospective offshore blocks A2 and A5 in The Gambia from ERIN Energy Corporation. The assignment was subject to approval by the Government of the Replublic of The Gambia which was granted on 29th June 2017. The farm-in deal with ERIN Energy requires FAR to fund ERIN up to US$8m through an exploration well expected to be drilled late in 2018. Blocks A2 and A5 are adjacent to and on trend with FAR’s giant SNE oil field and have significant exploration potential.

2017 FAR Annual Report 27

On 27th November 2017, FAR announced the results of an independent resources review conducted by RISC on FAR’s internal estimate of Prospective Resources for two large prospects mapped in permits A2 and A5, Samo and Bambo. Combined Prospective Resources for the two blocks were assessed at 1.1 billion barrels (unrisked, Best Estimate, recoverable, 100% basis) with 926 million barrels[*] net to FAR.

Guinea-Bissau

In April 2017, negotiations concluded with the national Oil Company of Guinea-Bissau, Petroguin to revise the terms of both the Sinapa and Esperanca Licenses to which FAR has interests. Under the revised licence terms, FAR has a 21.42% interest in the permit, an increase from 15% and FAR’s paying interest remains at 21.42%. These changes reflect that Petroguin will no longer have a participating interst in the joint venture prior to making a commercial discovery. In addition, the government also granted a 3 year extension to further evaluate the newly acquired 3D seismic data offshore Guinea-Bissau, which will now end on 25th November 2020.

Kenya L6

No technical work was completed in 2017 on block L6 due to continued land access issues. Once these access issues are rectified, FAR is planning to proceed with 2D onshore seismic survey. In the interim, the Ministry of Petroleum and Energy has consented to a temporary suspension of the permit work commitments.

Australia

As a result of the ongoing process of securing environmental approvals to complete the 3D seismic coverage over WA-458-P, FAR was granted a 24 month extension to the permit term which was granted in late 2017. Permit years 2, 3 and 4 (current permit period) will now end on 6 July 2019. During this period FAR will complete the 3D seismic survey. FAR intends to farm down its high interest in WA-458-P after acquisition of this 3D survey to focus on delivering shareholder value in the Senegal region. FAR submitted a request to surrender the WA-457-P permit in late 2016 and that process in ongoing however FAR remains in communication with NOPTA regarding the surrender and intends to leave the permit in good standing.

Subsequent events

On the 26th February 2018, FAR announced a farm in deal for blocks A2 and A5 to PETRONAS, the National Oil Company of Malaysia. The farm-in deal with PETRONAS requires PERONAS to fund 80% of total well costs through an exploration well, Samo-1, up to a maximum total cost of US$45.0 million.

Based on a completion date of 31 March 2018, FAR is to be paid estimated cash of US$13.5 million for reimbursement of back costs and cash consideration. In addition to this, PETRONAS will fund FAR’s share of non-well costs up to a maximum amount of US$1.5 million.

The Samo-1 well is expected to be drilled in late 2018 and will be the first exploration well offshore The Gambia since 1979. FAR estimates the Samo Prospect contains prospective resources of 825mmbbls oil[*] . FAR will remain Operator through the exploration phase of the A2/A5 licences, including the drilling of the Samo-1 well, and PETRONAS has a right to become the Operator for development.

LIKELY DEVELOPMENTS

Additional comments on expected results on operations of the Group are included in the Annual Report under the Operations Review.

The Group intends to continue its present range of activities during the forthcoming year. In accordance with its strategy, the Group may participate in exploration and appraisal wells and new projects, and may grow its exploration portfolio by farming into or acquiring new exploration licences. Other information on likely developments and the expected results of operations have not been included in this report, because, in the opinion of the directors, these would be speculative and it may not be in the best interests of the Group.

INDEMNIFICATION OF OFFICERS AND AUDITORS

During the financial year, the Company paid a premium in respect of a contract insuring the directors of the company, the company secretary and all executive officers of the company and of any related body corporate against a liability incurred as such a director, or company secretary to the extent permitted by the Corporations Act 2001. The contract of insurance prohibits disclosure of the nature of the liability and the amount of the premium.

The Company has not otherwise, during or since the end of the financial year, except to the extent permitted by law, indemnified or agreed to indemnify an officer or auditor of the Company or any of the related body corporate against a liability incurred as such an officer or auditor.

DIRECTORS’ MEETINGS

The following table sets out the number of directors’ meetings (including meetings of committees of directors) held during the financial year and the number of meetings attended (while they were a director or committee member) by each director:

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Board of Directors’ Remuneration Audit Committee Nomination Risk Committee
Meetings Committee meetings Committee
Held Attended Held Attended Held Attended Held Attended Held Attended
N J Limb 5 5 2 2 4 4 2 2 2 2
C M Norman 5 5 - - - - - - 2 2
B J M Clube 5 5 - - - - - - 2 2
R G Nelson 5 5 2 2 4 4 2 2 2 2
A E Brindal 1 1 1 1 2 2 1 1 - -
T R Woodall 3 3 1 1 2 2 1 1 2 2
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DIRECTORS’ REPORT

ENVIRONMENTAL REGULATIONS

The Group’s oil and gas operations are subject to environmental regulation under the legislation of the respective states and countries within which it operates. Approvals, licences, hearings and other regulatory requirements are performed by the operators of each permit or lease on behalf of joint operations in which the Group participates. The Group is potentially liable for any environmental damage from its activities, the extent of which cannot presently be quantified and would in any event be reduced by insurance carried by the Group or operator. The Group applies the extensive oil and gas experience of its personnel to develop strategies to identify and mitigate environmental risks. Compliance by operators with environmental regulations is governed by the terms of respective joint operating agreements and is otherwise conducted using oil industry best practices. The Board actively monitors compliance with state and joint operation regulations and as at the date of this report is not aware of any material breaches in respect of these regulations.

PROCEEDINGS ON BEHALF OF THE COMPANY

At the date of this report, the directors are not aware of any proceedings brought on behalf of the Company or Group, nor has any application been made in respect of the Company under section 237 of the Corporations Act 2001.

NON-AUDIT SERVICES

The Company may decide to employ the Auditor on assignments additional to their statutory audit duties where the Auditor’s expertise and experience with the Group is important.

The amounts paid or payable to the auditor for non-audit services provided during the year by the auditor are outlined in Note 26 to the financial statements.

1.1 Key Management personnel

The directors and other key management personnel of the consolidated entity during or since the end of the financial year were:

Non-Executve Directors	Positon
Nicholas James Limb	Chairman, Non-Executve Director
Reginald George Nelson	Non-Executve Director
Albert Edward Brindal (Retred 29 May 2017)	Non-Executve Director
Timothy Roy Woodall	Non-Executve Director
(Appointed 1 August 2017)
Executve directors and senior executves	Positon
Catherine Margaret Norman	Managing Director
Benedict James Murray Clube	Executve Director, Chief Operatng Ofcer
Peter John Nicholls	Exploraton Manager
Peter Anthony Thiessen	Chief Financial Ofcer and Company Secretary
Gordon Alexander Ramsay	Executve General Manager
(Ceased employment 11 April	Business Development
2017)
Michael Cowie	General Counsel
(appointed 1 February 2018)

Except as noted, the named persons held their positions for the whole of the financial year and since the end of the financial year.

AUDITOR’S INDEPENDENCE DECLARATION

The auditor’s independence declaration is included on page 40 of the Annual Report.

REMUNERATION REPORT – AUDITED

1. Introduction

This Remuneration Report, which forms part of the Directors’ Report, sets out information about the remuneration of FAR Ltd’s key management personnel (KMP) for the financial year ended 31 December 2017. The term ‘key management personnel’ refers to those persons having authority and responsibility for planning, directing and controlling the activities of the consolidated entity, directly or indirectly, including any director (whether executive or otherwise) of the consolidated entity. The prescribed details of each person covered by this report are detailed under the following headings:

key management personnel;
remuneration governance framework;
executive remuneration arrangements;
key terms of employment contracts;
executive remuneration tables; and
non-executive remuneration

2. Remuneration governance framework

The Remuneration Committee is responsible for reviewing and making recommendations on the remuneration packages of new and existing board members and senior executives and to oversee the remuneration of employees of the Company.

The objectives and responsibilities of the Remuneration Committee are documented in the charter approved by the board. A copy of the charter is available on the Company’s website.

The Remuneration Committee must comprise at least three members and consist of independent directors. The Remuneration Committee comprises of R G Nelson (Chairman), N J Limb, and T R Woodall (appointed 1 August 2017), each of whom are non-executive directors and considered by the company to be independent. A E Brindal was a member until he retired on 29 May 2017.

Objectives

The objectives of the remuneration Committee are definded in the charter and include:

To review and make recommendations on the remuneration packages of new and existing Board members and Senior Executives of FAR Limited.
To oversee the remuneration of employees of the Company.
The Committee makes recommendations to the Board of Directors and does not relieve the Board of its responsibilities in these matters.

2017 FAR Annual Report 29

Responsibilities

The responsibilities of the Remuneration Committee as defined in the charter are as follows:

Review and make recommendations to the Board on the remuneration packages of the roles of Chairman, Managing Director, other Directors and other Senior Executives;
Review and make recommendations to the Board on the remuneration packages, and terms and conditions of any new appointee to the roles of Chairman, Managing Director, other Directors and other Senior Executives;
Review the Managing Director’s recommendations in regard to proposed remuneration packages of employees;
Consider the adoption of appropriate long term and short term incentive and bonus plans and review adopted plans on a regular basis to ensure they comply with legislation and regulatory requirements, reflect industry standards and are effective in meeting the Company’s objectives;
Review participants in the incentive and bonus plans; and
Review the Remuneration Report as part of the Directors Report in the Annual Financial Statements of the Company.

3. Executive remuneration arrangements

3.1 Principles and strategy

Objectives

The Remuneration Committee advises the Board on remuneration for the Executives and oversees the Company’s executive remuneration policy which aims to:

reward executives fairly and responsibly in accordance with market rates and practices to ensure that the Company provides competitive rewards that attract, retain and motivate executives of a high calibre;
set high levels of performance which are clearly linked to an executive’s remuneration;
structure remuneration at a level that reflects the executive’s duties and accountabilities;
benchmark remuneration against appropriate comparator groups;
align executive incentive rewards with the creation of value for shareholders;
align remuneration with the Company’s long-term strategic plans and business objectives; and
comply with applicable legal requirements and appropriate governance standards.

Mix of remuneration

The Company policy is to remunerate executives under a Total Remuneration Package (TRP) which includes:

Fixed remuneration
Short term incentives – ‘at risk’ remuneration based on performance
Long term incentives – ‘at risk’ remuneration based on performance

Total remuneration packages for the Managing Director, Executive Director and Senior Executives comprise of the following components:

	Performance Remuneraton
	‘at risk’
	Fixed remuneraton Short term Incentves Long term Incentves**
Managing	50% 25% 25%
Director
Executve	50% 25% 25%
Director
Senior	50% 25% 25%
Executves

*percentage is relative to total fixed remuneration (TFR)

Benchmarking performance

The Company seeks to attract and retain suitably qualified senior executives and technical personnel and to ensure that salary packages are reasonable and competitive. To achieve this the Company has benchmarked fixed remuneration levels and ’at risk‘ remuneration structures for both short and long term incentive’s against data on Australian upstream oil and gas companies.

The Company seeks to return value to shareholders and incentivise executives to focus on the Company’s long-term strategy and growth opportunities. These incentives are conditional on performance conditions tied to the three year total shareholder return of the Company and to the three year total shareholder returns of the comparator group in the ASX 300 Energy Index.

Company performance

FAR’s remuneration policy is aimed at the alignment of KMP remuneration with the performance of the overall exploration and appraisal program and commercial transactions which ultimately result in shareholder value creation through share price. The following table outlines FAR’s financial performance over the last five years as required by the Corporations Act 2001.

DIRECTORS’ REPORT

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|||||||
|---|---|---|---|---|---|
|31 Dec 2017|31 Dec 2016|31 Dec 2015|31 Dec 2014|31 Dec 2013|
|$|$|$|$|$|
|Revenue|614,149|165,777|287,088|629,293|583,210|
|Loss from continuing operations|(42,779,180)|(21,759,974)|(19,620,11)|(6,937,168)|(7,955,349)|
|Loss from continuing & discontinued operations|(42,779,180)|(21,759,974)|(19,620,11)|(6,937,168)|(7,957,039)|
|31 Dec 2017|31 Dec 2016|31 Dec 2015|31 Dec 2014|31 Dec 2013|
|Share price at start of year|7.5 cents|8.3 cents|8.6 cents|4.0 cents|3.4 cents|
|Share price at end of year|7.7 cents|7.5 cents|8.3 cents|8.6 cents|4.0 cents|
|Dividend|-|-|-|-|-|
|Basic loss per share|(0.83) cps|(0.52) cps|(0.57) cps|(0.26) cps|(0.32) cps|
|Diluted loss per share|(0.83) cps|(0.52) cps|(0.57) cps|(0.26) cps|(0.32) cps|

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An overview of the Company’s policy with respect to each component of employee ‘pay mix’ is outlined below.

3.2 Fixed remuneration

Fixed remuneration consists of cash based salary and superannuation contributions.

Remuneration levels are reviewed annually by the Remuneration Committee. The process considers the individual performance having regard to overall Company performance. The Remuneration Committee seeks to ensure the Company retains and attracts talented, knowledgeable and an experienced workforce by ensuring the remuneration reflects market competitive rates, guided by P50 and is reflective of the individuals role, responsibilities and experience.

For details of fixed remuneration paid to senior executives and directors refer to sections 5.1, 5.1.2 and 6.

3.3 Short term incentives

Short term incentives (STI) are awarded in the form of cash bonuses. These benefits are ‘at risk’ based on performance during the year. They are designed to incentivise and provide competitive reward for achievement of Company wide and individual performance targets. Key Performance Indicators (KPI’s) are linked to strategic objectives.

For further details refer to section 5.1 and 5.2.

3.4 Long term incentives

Long term incentives (‘LTI’) are ‘at risk’ performance benefits awarded in the form of performance rights with vesting conditions tied to retention, Absolute Total Shareholder Return (‘TSR’) and Relative TSR.

The purpose of the LTI structure is to incentivise and provide competitive reward for continued service and achievement of long term strategic growth objectives.

LTI opportunities are reviewed and established (or deferred) annually by the Remuneration Committee at the beginning of each period, giving due consideration to the Company’s remuneration principles.

Performance Rights Plan and the remuneration policy

The shareholders of the Company approved a Performance Rights Plan at the annual general meeting held on 13 May 2016. The Performance Rights Plan was put in place for the award of long term performance benefits.

The Plan is designed to:

promote the long term success of the Group,
provide strategic, value based reward for Eligible Persons who make a key contribution to that success
align Eligible Persons interests with the interests of the Company’s shareholders and
promote the retention of Eligible Persons.

The key elements of the remuneration policy together with the Plan include:

Rights are granted at the discretion of the Board based on the recommendation of the Remuneration Committee and the percentages relative to total fixed remuneration (TFR). Due consideration to the number of shares and incentives on issue and issued in the prior five years.
The performance measures with separate vesting criteria include:
Relative Total Shareholder Return (‘TSR’) and
‒ Absolute TSR
The vesting period is for three years and lapse after three years if not vested.
Rights granted in a particular financial year are tested for vesting over the performance period.
Generally, with respect to TSR provisions, vesting will occur on a proportionate straight-line basis for performance as follows: ‒ between threshold and target for Absolute TSR and
between 50P and 75P for Relative TSR.

2017 FAR Annual Report 31

Vesting of performance rights will typically be subject to continuing employment of the eligible executives. Subject to director discretion, rights will generally lapse on an executive’s resignation or dismissal. In exceptional circumstances and where a termination is for reasons including retirement, death, total and permanent disablement, change of control and bona fide redundancy, unless it determines otherwise, the Board has the discretion to determine the extent to which all or part of any unvested equity may vest and the specific performance testing to be applied.

The maximum number of rights that can be granted as a percentage of fixed remuneration at the time of grant and converted to a number of rights using the 20 day volume weighted average price (‘VWAP’) of the FAR share price preceding grant is as follows:

Maximum percentage of Fixed Remuneration on which the number of rights are calculated

	Absolute TSR vestng conditon Relatve TSR vestng conditon Total
Managing	12.5% 12.5% 25%
Director
Executve	12.5% 12.5% 25%
Director
Senior	12.5% 12.5% 25%
executves

The above table represents the maximum percentage of fixed remuneration on which the number of rights to be awarded are calculated.

Absolute TSR grants

Number of rights calculated using the 20-day VWAP of the FAR share price preceeding 1 February each year
Vest after the three year performance period according to the Company’s Absolute TSR for that three year period
The vesting scales to apply for Absolute TSR grants are as follows:

Relative TSR

Number of rights calculated using the 20-day VWAP of the FAR share price preceeding 1 February each year
Vest after the three year performance period according to the Company’s TSR relative to the comparator group companies in the S&P/ASX Energy 300 Index.
The vesting scales to apply for Absolute TSR grants are as follows:

FAR TSR relatve to TSR of
comparator group companies
in S&P/ASX Energy 300 Index	% of rights to vest
<50	-
50%	50%
>50% and <75%	Pro rata
75%	100%

For an analysis of rights granted, vested and forfeited for the year ended 31 December 2017, refer to section 5.3.1.

Employee Share Option Plan

The shareholders of the Company approved an Executive Incentive Plan at the annual general meeting held on 15 May 2015, prior to then the Company did not have a formal share-based compensation scheme and granted options at the discretion of the board. In accordance with the provisions of the approved plan, the board at its discretion may grant options to any full-time or permanent part-time employee or officer, or director of the Company to purchase parcels of ordinary shares. All options issued to directors are granted in accordance with a resolution of shareholders.

Each employee option converts into one ordinary share of FAR Ltd on exercise. No amounts are paid or payable by the recipient on receipt of the option. The options neither carry rights to dividends nor voting rights. Options may be exercised at the applicable exercise price from the date of vesting to the date of expiry. See section 5.3.2 for exercise prices. No options were granted during the year.

•The vestng scales to apply for as follows:	Absolute TSR grants are
FAR TSR	% of rights to vest
<15% CAGR	-
15% CAGR	50%
>15% and <25% CAGR	Pro rata
25% CAGR	100%

CAGR = Compound Annual Growth

DIRECTORS’ REPORT

4. Key terms of employment contracts

The table below details the key terms of the employment contracts for the Managing Director, Executive Director and Chief Operating Officer and other Senior Executives of the Company:

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Name Contract duration Termination notice by Termination notice by
the company the executive
C M Norman Ongoing, no fixed term 12 months 3 months
B J M Clube Ongoing, no fixed term 12 months 3 months
G A Ramsay [ (ii)] Ongoing, no fixed term 12 months 2 months
P A Thiessen Ongoing, no fixed term 12 months 2 months
P J Nicholls [ (i)] Ongoing, no fixed term By giving notice of a breach
of contract
M Cowie [ (iii)] Ongoing, no fixed term 2 months 2 months
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(i) P J Nicholls is a consultant and not an employee of the Company. For further details section 4.

(ii) G A Ramsay ceased employment on 11 April 2017.

(iii) M Cowie was appointed 1 February 2018.

5. Executive Remuneration tables

5.1 Remuneration tables

The table below details the remuneration of the Managing Director, Executive Director and Chief Operating Officer and other Executives for the year.

2017	Short-term employee benefts	Short-term employee benefts	Post-	Share-based
			employment	payment
Name	Salary	Bonus(iii) Terminaton	Super	Optons /	Long service	Total
	and fees			Rights	leave
C M Norman	667,917	68,458	- 32,083	72,848	68,246 909,552
B J M Clube	567,917	58,678	- 32,083	62,913	36,298 757,888
P J Nicholls(i)	529,650	44,453	- -	85,616		- 659,719
G A Ramsay(ii)	119,354	- 470,138 29,921		(6,942)		- 612,471
P A Thiessen	322,917	32,229	- 27,083	61,157	19,898 463,285
						3,402,915

						3,402,915
2016	Short-term employee benefts			Post-	Share-based
				employment	payment
Name	Salary	Bonus	Terminaton	Super	Optons /	Long service Total
	and fees				Rights	leave
C M Norman	528,562		-	- 30,000	371,573	19,313 949,448
B J M Clube	452,362		-	- 30,000	300,115	25,707 808,184
P J Nicholls(i)	452,550		-	- -	296,475	- 749,025
G A Ramsay(iI)	422,062		-	- 35,000	298,082	2,604 757,748
P A Thiessen	270,262		-	- 30,000	285,468	11,450 597,180
						3,861,585

(i) P J Nicholls is a consultant and not an employee of the Company. For further details section 4.

(ii) G A Ramsay ceased employment on 11 April 2017.

(iii) A bonus in respect of the year ended 31 December 2017 year was paid in March 2018 to KMP. For further details on the bonus paid to KMP see section 5.2.

2017 FAR Annual Report 33

5.1.2 Actual pay

The table below provides a summary of actual remuneration paid to the Executives in the 2017 year. The accounting values of the Executives’ remuneration reported in accordance with the Accounting Standards may not always reflect what the Executives have actually received, particularly due to the valuation of the

share based payments. The table below seeks to clarify this by setting out the actual remuneration that the Executives have been paid in the financial year. Executive remuneration details prepared in accordance with statutory requirements and the Standards are presented in 5.1 Remuneration table.

2017 Salary and fees Terminaton Bonus Superannuaton	Total
C M Norman 667,917 - 68,458 32,083	768,458
B J M Clube 567,917 - 58,678 32,083	658,678
P J Nicholls 529,650 - 44,453 -	574,103
G A Ramsay(i) 119,354 470,138 - 29,921	619,413
P A Thiessen 322,917 - 32,229 27,083	382,229
	3,002,881

2016 Salary and fees Terminaton Bonus Superannuaton	Total
C M Norman 528,562 - - 30,000	558,562
B J M Clube 452,362 - - 30,000	482,362
P J Nicholls 452,550 - - -	452,550
G A Ramsay(i) 422,062 - - 35,000	457,062
P A Thiessen 270,262 - - 30,000	300,262
	2,250,798

(i) G A Ramsay ceased employment on 11 April 2017

The KMP salaries were benchmarked against its Australian listed Oil and Gas peers at the end of the 2016 year and were found to be at the bottom of its peer group. Having considered the individuals performance, the desire to retain their talent and experience the remuneration committee and board approved increases to their salaries to align with market competitive rates.

5.2 Analysis of Short term incentives

Members of the senior executive team were eligible to participate in the Company’s 2017 STI plan. The 2017 KPI targets were aligned with the remuneration policy guidance which included financial, corporate and strategic objectives.

Certain measures were identified as core drivers of value for shareholders and were selected to encourage activities and behaviours aligned with the Company’s strategy, risk framework and governance principles. Multiple objectives were set within the various performance areas. Group financial indicators included for example, objectives related to managing cash flow; operational performance indicators included risk management and cost control initiatives; and Corporate strategy and governance indicators including measures related to risk, leadership, corporate culture and governance.

Executive performance against the 2017 KPI’s were tested and the outcomes were as follows:

Executve	At target STI opportunity % of TFR Stretch STI opportunity % of TFR 2017 actual STI award relatve to TFR %	2017 actual STI award $
C Norman – MD	12.5 12.5 9.8	68,458
B Clube – ED and COO	12.5 12.5 9.8	58,678
P Nicholls – Exploraton	12.5 12.5 8.4	44,453
Manager
P Thiessen - CFO	12.5 12.5 9.8	32,229

Executive bonuses for 2017 performance will be paid in cash (less superannuation and applicable taxation) in Q1 2018 in accordance with the Company’s remuneration policy.

For further details on short term incentives see section 3.3.

DIRECTORS’ REPORT

5.3 Analysis of Long term incentives

For further details on long term incentives see section 3.4.

During the year the Company granted Performance Rights under the Performance Rights Plan.

Performance against the Absolute and Relative TSR criteria in respect of the Performance Rights will be measured at the end of the performance periods at 31 January 2019 and 31 January 2020.

5.3.1 Details of Performance Rights Granted

The value of Performance Rights are allocated to each reporting period over the period from grant date to vesting date.

Details of the Performance Rights granted to Executives during the year are as follows:

The Company did not grant any options under the Executive Incentive Plan during the year.

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Number of
rights granted Grant Fair value Total Exercise price Expiry
2017 during the year [ (i)] date per right [ (ii)] value per right date [ (iv)]
P J Nicholls 2,916,000 31-May-17 0.0447 130,339 $0.00 31-Jan-22
P A Thiessen 2,243,000 31-May-17 0.0447 100,257 $0.00 31-Jan-22
Number of
rights granted Grant Fair value Total Exercise price Expiry
2016 during the year [ (i)] date per right [ (ii)] value per right date [ (iv)]
C M Norman [ (iii)] 3,578,000 20-May-16 0.055 196,790 $0.00 31-Jan-21
B J M Clube [ (iii)] 3,090,000 20-May-16 0.055 169,950 $0.00 31-Jan-21
P J Nicholls 2,800,000 20-May-16 0.055 154,000 $0.00 31-Jan-21
G A Ramsay [ (i)] 2,928,000 20-May-16 0.055 161,040 $0.00 31-Jan-21
P A Thiessen 1,923,000 20-May-16 0.055 105,765 $0.00 31-Jan-21
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(i) The vesting of rights is conditional upon satisfaction of vesting conditions as described in section 3.4. The Base Price of the Performance Rights granted during the year is 7.8 cents (2016: 7.8 cents) which represents the 20 day VWAP preceeding 1 February 2017 (2016: 1 February 2016).

(ii) The fair value per right granted represents the valuation of rights granted and calculated at grant date.

(iii) Grants of rights to C M Norman and B J M Clube have been approved by shareholders at the Annual General Meeting held in May 2016.

(iv) The performance period for the performance rights granted during the year is from 1 February 2017 to 31 January 2020 (2016: 1 February 2016 to 31 January 2019.

The TSR is calculated by comparing the Base Price against the share price on the Test Date plus any dividends paid throughout the Performance Period, which is then computed into an equivalent per annum return. For the purposes of the Absolute TSR test, the Board have elected to set the Base Price of FAR Shares as at 1 February 2017 at $0.078 per Share, which is the 20 day volume weighted average price (VWAP) preceding 1 February 2017. Performance against this criteria will be measured at the end of the performance period, 31 January 2020.

The TSR performance of FAR Shares will be compared to the TSR performance of all other shares in a comparator group, being the S&P/ASX Energy 300 Index, and Performance Rights will vest only if FAR’s TSR performance is at least at the 50th percentile. Performance against this criteria will be measured at the end of the performance period, 31 January 2020.

The movement during the financial year in the number of Performance Rights held by the Managing Director, Executive Director and Senior Executives is detailed below:

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Movements in Opening Granted as Exercised Lapsed Net other Closing
Performance Rights balance remuneration unexercised change balance
C M Norman 3,578,000 - - - - 3,578,000
B J M Clube 3,090,000 - - - - 3,090,000
P J Nicholls 2,800,000 2,916,000 - - - 5,716,000
G A Ramsay [(i)] 2,928,000 - - (2,928,000) - -
P A Thiessen 1,923,000 2,243,000 - - - 4,166,000
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(i) G A Ramsay ceased employment on 11 April 2017

2017 FAR Annual Report 35

5.3.2 Details of Options Granted

No options were granted during the year.

Terms and conditions of the options granted in prior years and affecting remuneration in prior financial years were as follows:

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Options series Grant Grant date Exercise Expiry Vesting Vesting
date fair value price date percentage date
Series 11 1 Jul 2015 8.7 cents 10.0 cents 1 Jun 2018 100% Vested on 26 October 2016 [1]
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The options vested on 26 October 2016 as determined by the board having satisfied itself the vesting condition of an announcement to the effect of potential economic viability of a future development project by the Operator of the Senegal joint operation, was met.

The movement during the year in the number of options held by the executive and non-executive directors and senior executives are detailed below:

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For the year ended Balance Granted as Net Other Balance
31 Dec 2017 1 Jan 17 Remuneration Exercised Change 31 Dec 17
Directors
C M Norman [ (i)] 10,000,000 - - - 10,000,000
B J M Clube [ (i)] 8,000,000 - - - 8,000,000
N J Limb - - - - -
R G Nelson 5,000,000 - - - 5,000,000
Key Executives
P J Nicholls 8,000,000 - - - 8,000,000
P A Thiessen 8,000,000 - - - 8,000,000
G A Ramsay [ (ii)] 8,000,000 - - (8,000,000) -
47,000,000 - - (8,000,000) 39,000,000
For the year ended Balance Granted as Net Other Balance
31 Dec 2016 1 Jan 16 Remuneration Exercised Change 31 Dec 16
Directors
C M Norman [ (i)] 24,000,000 - (14,000,000) - 10,000,000
B J M Clube [ (i)] 20,000,000 - (12,000,000) - 8,000,000
N J Limb 5,000,000 - (5,000,000) - -
R G Nelson 5,000,000 - - - 5,000,000
Key Executives
P J Nicholls 18,000,000 - (10,000,000) - 8,000,000
P A Thiessen 14,000,000 - (6,000,000) - 8,000,000
- - -
G A Ramsay 8,000,000 8,000,000
- -
94,000,000 (47,000,000) 47,000,000
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(i) Grants of options to C M Norman and B J M Clube were approved by shareholders at Annual General Meetings of prior years.

(ii) G A Ramsay ceased employment on 11 April 2017.

During the year no options were exercised.

DIRECTORS’ REPORT

5.4 Analysis of movement in shareholdings

The number of shares held, directly, indirectly or beneficially, by parent company directors and senior executives are outlined in the tables below.

For the year ended 31 Dec 2017	Balance 1 Jan 17 Received on Exercise of Optons Net Other Change(i) Balance 31 Dec 17
Directors C M Norman	18,674,090 - 18,674,090
B J M Clube	23,732,000 - 23,732,000
N J Limb	39,908,139 - 39,908,139
A E Brindal(ii)	350,955 (350,955) -
R G Nelson	500,000 - 500,000
T R Woodall(iii)	- 1,500,000 1,500,000
Key Executves P J Nicholls	9,113,291 - 9,113,291
G A Ramsay(iv)	550,000 (550,000) -
P A Thiessen	7,062,500 - 7,062,500
For the year ended 31 Dec 2016	99,890,975 599,045 100,490,020

	Balance 1 Jan 16 Received on Exercise of Optons Net Other Change Balance 31 Dec 16
Directors C M Norman	4,674,090 14,000,000 - 18,674,090
B J M Clube	11,732,000 12,000,000 - 23,732,000
N J Limb	34,908,139 5,000,000 - 39,908,139
A E Brindal(ii)	350,955 - - 350,955
R G Nelson	500,000 - - 500,000
Key Executves P J Nicholls	4,543,291 10,000,000 (5,430,000) 9,113,291
G A Ramsay(iv)	550,000 - - 550,000
P A Thiessen	1,062,500 6,000,000 - 7,062,500
	58,320,975 47,000,000 (5,430,000) 99,890,975

(i) Net Other Change represents shares purchased or sold on market during the period, shareholdings recognised upon KMP appointment or de-recognised upon retirement or ceasing employment.

(ii) A E Brindal retired as a director on 29 May 2017 and consequently ceased as a KMP member on this date. Mr Brindal’s shareholding at this date has been de-recognised in ‘net other change’.

(iii) T R Woodall was appointed a director on 1 August 2017 and consequently was recognised as a KMP member on this date. Mr Woodall’s shareholding at this date has been recognised in ‘net other change’.

(iv) G A Ramsay ceased employment on 11 April 2017 and consequently ceased as a KMP member on this date. Mr Ramsay’s shareholding at this date has been de-recognised in ‘net other change’.

6. Non-executive remuneration

The Company’s remuneration policy for non-executive directors considers the following factors when determining levels of remuneration:

the size, activities and structure of the Company;
the location and jurisdictions in which the Company operates;
the responsibilities and work commitment requirements of Board members; and
the level of fees paid to non-executive directors relative to comparable companies.

Fees paid to non-executive directors are determined by the Board and are subject to an aggregate limit of A$600,000 per annum in accordance with the Company’s constitution and as approved by shareholders at the Annual General Meeting held in May 2017.

2017 FAR Annual Report 37

The non-executive directors remuneration policy is as follows:

Remuneration includes a fixed fee for their services as directors and statutory superannuation (where applicable).
Entitlement to reimbursement of reasonable travel, accommodation and other expenses incurred whilst engaged on Company business.
At the Board’s discretion, additional fees may be paid for special duties or extra services performed on behalf of the Company.
No provision for retirement benefits other statutory superannuation entitlement.
No entitlement to participate in incentive based remuneration schemes from 1 January 2016.
No additional fees are paid for participation on any Board committees.

•No additonal fees are pa commitees.	id for partcipaton on any	Board
2017	Short-term employee	Post-employment	Share-based payment	Total
	benefts
Name	Director fees	Super Contributon	Optons / Rights
Non-Executve Directors
N J Limb	200,000		- -		200,000
A E Brindal(i)	20,833		- -		20,833
R G Nelson	91,324	8,676 -			100,000
T R Woodall(ii)	41,667		- -		41,667
2016	Short-term employee	Post-employment	Share-based payment	Total
	benefts
Name	Director fees	Super Contributon	Optons / Rights(iii)
Non-Executve Directors
N J Limb	200,000		- -		200,000
A E Brindal(i)	20,833		- -		20,833
R G Nelson	91,324	8,676 -			100,000

(i) A E Brindal retired as a director on 29 May 2017.

(ii) T R Woodall appointed as a director on 1 August 2017.

Loans to KMP

No loans were made to KMP during the year, nor any loans to KMP outstanding.

Director related transactions

Loans to related parties

No loans were made to director related parties during the year.

Transactions with director related entities

The terms and conditions of transactions with KMP were no more favourable to KMP and their related entities than those available, or which might reasonably be expected to be available, on similar transactions to KMP related entities on an arm’s length basis.

No hedging of remuneration of key management personnel

No member of the key management personnel has entered into an arrangement (with anyone) to limit the exposure of the member to risk relating to an element of the members remuneration that has not vested in the member, or has vested in the member but remains subject to a holding lock.

The directors’ report is signed in accordance with a resolution of the directors made pursuant to Section 298(2) of the Corporations Act 2001.

On behalf of the directors

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Nicholas J Limb Chairman

Melbourne, 20 March 2018

FINANCIAL REPORT 2017

FAR builds opportunity to add significant shareholder value through near term exploration drilling success

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2017 FAR Annual Report 39

AUDITOR’S INDEPENDENCE DECLARATION

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Deloitte Touche Tohmatsu ABN 74 490 121 060

550 Bourke Street Melbourne VIC 3000 GPO Box 78 Melbourne VIC 3001

The Board of Directors FAR Limited Level 17, 530 Collins Street Melbourne VIC 3000

Tel: +61 3 9671 7000 Fax: +61 3 9671 7001 www.deloitte.com.au

20 March 2018

Dear Board Members

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

As lead audit partner for the audit of the financial statements of FAR Limited for the financial year ended 31 December 2017, I declare that to the best of my knowledge and belief, there have been no contraventions of:

(i) the auditor independence requirements of the Corporations Act 2001 in relation to the audit; and

(ii) any applicable code of professional conduct in relation to the audit.

Yours sincerely

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DELOITTE TOUCHE TOHMATSU

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Ryan Hansen Partner Chartered Accountants

Liability limited by a scheme approved under Professional Standards Legislation.

Member of Deloitte Touche Tohmatsu Limited

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INDEPENDENT AUDITOR’S REPORT

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Deloitte Touche Tohmatsu ABN 74 490 121 060 550 Bourke Street Melbourne VIC 3000 GPO Box 78 Melbourne VIC 3001

Tel: +61 3 9671 7000 Fax: +61 3 9671 7001 www.deloitte.com.au

Independent Auditor’s Report to the members of FAR Limited

Report on the Audit of the Financial Report

Opinion

We have audited the financial report of FAR Limited (the “Company”) and its subsidiaries (the “Group”), which comprises the consolidated statement of financial position as at 31 December 2017, the consolidated statement of profit or loss and other comprehensive income, the consolidated statement of cash flows and the consolidated statement of changes in equity for the year then ended, and notes to the financial statements, including a summary of significant accounting policies, and the directors’ declaration.

In our opinion, the accompanying financial report of the Group is in accordance with the Corporations Act 2001 , including:

(i) giving a true and fair view of the Group’s financial position as at 31 December 2017 and of its financial performance for the year then ended; and

(ii) complying with Australian Accounting Standards and the Corporations Regulations 2001 .
Basis for Opinion

We conducted our audit in accordance with Australian Auditing Standards. Our responsibilities under those standards are further described in the Auditor’s Responsibilities for the Audit of the Financial Report section of our report. We are independent of the Group in accordance with the auditor independence requirements of the Corporations Act 2001 and the ethical requirements of the Accounting Professional and Ethical Standards Board’s APES 110 Code of Ethics for Professional Accountants (the Code) that are relevant to our audit of the financial report in Australia. We have also fulfilled our other ethical responsibilities in accordance with the Code.

We confirm that the independence declaration required by the Corporations Act 2001 , which has been given to the directors of the Company, would be in the same terms if given to the directors as at the time of this auditor’s report.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Key Audit Matters

Key audit matters are those matters that, in our professional judgement, were of most significance in our audit of the financial report for the current period. These matters were addressed in the context of our audit of the financial report as a whole, and in forming our opinion thereon, and we do not provide a separate opinion on these matters.

Liability limited by a scheme approved under Professional Standards Legislation.

Member of Deloitte Touche Tohmatsu Limited

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2017 FAR Annual Report

INDEPENDENT AUDITOR’S REPORT

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Key Audit Matter

How the scope of our audit responded to the Key Audit Matter

Accounting for exploration and evaluation costs

As at 31 December 2017 the Group incurred $70 million in exploration and evaluation (E&E) costs during the period, of which $35 million has been capitalised and all other E&E costs were expensed as disclosed in Note 3(p). Significant judgement is required by management in determining whether:

the criteria for capitalisation are met, in particular whether E&E costs are expected to be recouped through successful development and exploitation of the area of interest or by future sale or that the activities in the area of interest have not reached the point that a reasonable assessment of economically recoverable reserves can be made.

Our audit procedures included, but were not limited to:

Assessing the key processes and controls associated with the allocation of E&E costs between capital and expense,
Confirming the rights to tenure of the areas of interest are current and challenging management’s consideration of the ability to recoup the capitalised costs through future development or sale of the area of interest,
Confirming whether exploration activities for the area of interest had reached a stage where a reasonable assessment of economically recoverable reserves existed, and
Testing a sample of E&E expenditure to confirm the nature of the costs incurred, and the appropriateness of the classification between asset and expense. This included an assessment as to whether the capitalised amounts related to only drilling costs, delineation seismic and other costs directly attributable to defining specific geological targets.

We also assessed the appropriateness of the disclosures in Note 11 to the financial statements.

Recoverability of exploration and evaluation assets

As at 31 December 2017 the carrying amount of E&E assets is $128.7 million, as disclosed in Note 11.

Significant judgement is applied by management in determining whether ongoing exploration projects or market conditions have changed indicating that the exploration and expenditure assets should be tested for impairment in accordance with the applicable accounting standards.

Our audit procedures included, but were not limited to:

Assessing management’s processes surrounding the evaluation of the facts and circumstances that may suggest the carrying value of E&E assets exceeds the recoverable amount,
Challenging management’s assessment that may suggest E&E assets are not fully recoverable, including but not limited to:
Testing licenses for the areas of interest to determine whether the license has expired during the period or will expire in the near future with no expectation to be renewed,
Reviewing budgets to determine whether substantive expenditure in an area of interest is neither budgeted nor planned,
Evaluating management’s assessment as to whether evaluation of mineral resources in a specific area of interest have not led to the discovery of commercially viable quantities of mineral resources and the Company has decided to discontinue further evaluation of the area,
Challenging management as to whether sufficient data exists that suggests E&E assets related to a specific area of interest will not be recovered in full from successful development or by sale, and
Assessing the current status and future intention for each asset given the status of technical feasibility and commercial viability of extraction are not yet demonstrable across any exploration assets.

We have also assessed the appropriateness of the disclosures in Note 11 to the financial statements.

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Other Information

The directors are responsible for the other information. The other information comprises the information included in the Group’s annual report for the year ended 31 December 2017, but does not include the financial report and our auditor’s report thereon.

Our opinion on the financial report does not cover the other information and we do not express any form of assurance conclusion thereon.

In connection with our audit of the financial report, our responsibility is to read the other information and, in doing so, consider whether the other information is materially inconsistent with the financial report or our knowledge obtained in the audit, or otherwise appears to be materially misstated. If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.

Responsibilities of the Directors for the Financial Report

The directors of the Company are responsible for the preparation of the financial report that gives a true and fair view in accordance with Australian Accounting Standards and the Corporations Act 2001 and for such internal control as the directors determine is necessary to enable the preparation of the financial report that gives a true and fair view and is free from material misstatement, whether due to fraud or error.

In preparing the financial report, the directors are responsible for assessing the ability of the Group to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless the directors either intend to liquidate the Group or to cease operations, or has no realistic alternative but to do so.

Auditor’s Responsibilities for the Audit of the Financial Report

Our objectives are to obtain reasonable assurance about whether the financial report as a whole is free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with the Australian Auditing Standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of this financial report.

As part of an audit in accordance with the Australian Auditing Standards, we exercise professional judgement and maintain professional scepticism throughout the audit. We also:

Identify and assess the risks of material misstatement of the financial report, whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.
Obtain an understanding of internal control relevant to the audit in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Group’s internal control.
Evaluate the appropriateness of accounting policies used and the reasonableness of accounting estimates and related disclosures made by the directors.
Conclude on the appropriateness of the directors’ use of the going concern basis of accounting and, based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Group’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the financial report or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Group to cease to continue as a going concern.
Evaluate the overall presentation, structure and content of the financial report, including the disclosures, and whether the financial report represents the underlying transactions and events in a manner that achieves fair presentation.
Obtain sufficient appropriate audit evidence regarding the financial information of the entities or business activities within the Group to express an opinion on the financial report. We are responsible for the direction, supervision and performance of the Group audit. We remain solely responsible for our audit opinion.

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2017 FAR Annual Report 43

INDEPENDENT AUDITOR’S REPORT

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We communicate with the directors regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

We also provide the directors with a statement that we have complied with relevant ethical requirements regarding independence, and to communicate with them all relationships and other matters that may reasonably be thought to bear on our independence, and where applicable, related safeguards.

From the matters communicated with the directors, we determine those matters that were of most significance in the audit of the financial report of the current period and are therefore the key audit matters. We describe these matters in our auditor’s report unless law or regulation precludes public disclosure about the matter or when, in extremely rare circumstances, we determine that a matter should not be communicated in our report because the adverse consequences of doing so would reasonably be expected to outweigh the public interest benefits of such communication.

Report on the Remuneration Report

Opinion on the Remuneration Report

We have audited the Remuneration Report included in pages 29 to 38 of the Directors’ Report for the year ended 31 December 2017.

In our opinion, the Remuneration Report of FAR Limited, for the year ended 31 December 2017, complies with section 300A of the Corporations Act 2001 .

Responsibilities

The directors of the Company are responsible for the preparation and presentation of the Remuneration Report in accordance with section 300A of the Corporations Act 2001 . Our responsibility is to express an opinion on the Remuneration Report, based on our audit conducted in accordance with Australian Auditing Standards.

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DELOITTE TOUCHE TOHMATSU

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Ryan Hansen Partner Chartered Accountants Melbourne, 20 March 2018

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DIRECTORS’ DECLARATION

The directors declare that:

(a) in the directors’ opinion, there are reasonable grounds to believe that the Company will be able to pay its debts as and when they become due and payable;
(b) the attached financial statements are in compliance with International Financial Reporting Standards, as stated in Note 3 to the financial statements;
(c) in the directors’ opinion, the attached financial statements and notes thereto are in accordance with the Corporations Act 2001, including compliance with accounting standards and giving a true and fair view of the financial position and performance of the Group; and
(d) the directors have been given the declarations required by s.295A of the Corporations Act 2001.

At the date of this declaration, the Company is within the class of companies affected by ASIC Class Order 98/1418. The nature of the deed of cross guarantee is such that each company which is party to the deed guarantees to each creditor payment in full of any debt in accordance with the deed of cross guarantee.

In the directors’ opinion, there are reasonable grounds to believe that the Company and the Companies to which the ASIC Class Order applies, as detailed in Note 19 to the financial statements, will, as a group, be able to meet any obligations or liabilities to which they are, or may become, subject by virtue of the deed of cross guarantee.

Signed in accordance with a resolution of the directors made pursuant to s.295(5) of the Corporations Act 2001.

On behalf of the directors

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Nicholas J Limb Chairman Melbourne, 20 March 2018

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2017 FAR Annual Report 45

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

For the financial year ended 31 December 2017

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|||||
|---|---|---|---|
|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|
|Note|AU$|AU$|
|Interest income|614,149|165,777|
|-|-|
|Gain on recovery of back costs|
|Depreciation and amortisation expense|6|(40,330)|(41,033)|
|Exploration expense|(35,200,227)|(16,352,405)|
|Corporate administration expenses|(854,891)|(767,614)|
|Employee benefits expense|6|(3,266,738)|(4,612,423)|
|Corporate consulting expense|(318,905)|(513,550)|
|Foreign exchange gain/(loss)|(3,367,979)|767,004|
|Other expenses|(344,259)|(405,730)|
|Loss before income tax|(42,779,180)|(21,759,974)|
|Income tax expense|7|-|-|
|LOSS FOR THE YEAR|(42,779,180)|(21,759,974)|
|Other comprehensive income / (loss), net of income tax|
|Items that may be reclassified subsequently to profit or loss|
|Exchange differences arising on translation of foreign operations|(7,467,185)|1,654,452|
|Other comprehensive gain for the year, net of the income tax|(7,467,185)|1,654,452|
|TOTAL COMPREHENSIVE LOSS FOR THE YEAR|(50,246,365)|(20,105,522)|
|Earnings per share:|
|From continuing operations|
|Basic loss (cents per share)|15|(0.83)|(0.52)|
|Diluted loss (cents per share)|15|(0.83)|(0.52)|

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Notes to the financial statements are included on pages 50 to 77.

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CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at 31 December 2017

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|||||
|---|---|---|---|
|Year ended|Year ended|
|Note|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|CURRENT ASSETS|
|Cash and cash equivalents|20(a)|49,926,796|46,978,179|
|Trade and other receivables|8|2,148,325|2,575,664|
|Other financial assets|9|123,489|120,299|
|Total Current Assets|52,198,610|49,674,142|
|NON CURRENT ASSETS|
|Property, plant and equipment|10|359,380|319,467|
|Exploration and evaluation assets|11|128,734,644|101,706,766|
|Total Non-Current Assets|129,094,024|102,026,233|
|TOTAL ASSETS|181,292,634|151,700,375|
|CURRENT LIABILITIES|
|Trade and other payables|12|8,569,700|5,958,709|
|Provisions|13|1,024,985|885,571|
|Total Current Liabilities|9,594,685|6,844,280|
|NON CURRENT LIABILITIES|
|Provisions|13|110,378|55,870|
|Total Non-Current Liabilities|110,378|55,870|
|TOTAL LIABILITIES|9,705,063|6,900,150|
|NET ASSETS|171,587,571|144,800,225|
|EQUITY|
|Issued Capital|14|374,521,076|297,933,534|
|Reserves|5,506,390|12,527,406|
|Accumulated losses|(208,439,895)|(165,660,715)|
|TOTAL EQUITY|171,587,571|144,800,225|

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Notes to the financial statements are included on pages 50 to 77.

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2017 FAR Annual Report 47

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the financial year ended 31 December 2017

Reserves Share capital AU$ Share based payments reserve (i) AU$ Foreign currency translaton reserve (ii) AU$ Total AU$ Accumulated losses AU$ Total atributable to equity holders of the parent AU$
Balance at 1 January 2016 237,806,280 5,955,222 2,427,509 8,382,731 (143,900,741) 102,288,270
Loss for the year - - - - (21,759,974) (21,759,974)
Other Comprehensive income for the year, net of income tax - - 1,654,452 1,654,452 - 1,654,452
Total comprehensive income for the year - - 1,654,452 1,654,452 (21,759,974) (20,105,522)
Recogniton of share-based payments - 2,490,223 - 2,490,223 - 2,490,223
Issue of ordinary shares 60,000,000 - - - - 60,000,000
Issue of ordinary shares under share opton plan 2,728,000 - - - - 2,728,000
Share issue costs (2,600,746) - - - - (2,600,746)
Balance at 31 December 2016 297,933,534 8,445,445 4,081,961 12,527,406 (165,660,715) (144,800,225)
Loss for the year - - - - (42,779,180) (42,779,180)
Other comprehensive income for the year, net of income tax - - (7,467,185) (7,467,185) - (7,467,185)
Total comprehensive income/loss for the year - - (7,467,185) (7,467,185) (42,779,180) (50,246,365)
Recogniton of share-based payments - 446,169 - 446,169 - 446,169
Issue of ordinary shares 80,000,000 - - - - 80,000,000
Share issue costs (3,412,458) - - - - (3,412,458)
Balance at 31 December 2017 374,521,076 8,891,614 (3,385,224) 5,506,390 (208,439,895) 171,587,571

(i) This comprises the fair value of rights and options recognised as an employee expense.

(ii) Foreign currency translation reserve represents the foreign currency movement on the revaluation of assets and liabilities held in currencies other than AUD.

Notes to the financial statements are included on pages 50 to 77.

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CONSOLIDATED STATEMENT OF CASH FLOWS

For the financial year ended 31 December 2017

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|||||
|---|---|---|---|
|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|
|Note|AU$|AU$|
|CASH FLOWS FROM OPERATING ACTIVITIES|
|Payments to suppliers and employees|(4,461,607)|(3,643,675)|
|Payments for exploration and evaluation expensed|(30,800,533)|(17,129,854)|
|Net cash used in operating activities|20(d)|(35,262,140)|(20,773,529|
|CASH FLOWS FROM INVESTING ACTIVITIES|
|Interest received|598,650|154,242|
|Payments for oil and gas properties capitalised|(28,206,395)|(53,807,962)|
|Payments for property, plant and equipment|(127,552)|(56,208)|
|-|
|Payment of farm-in costs|(7,109,497)|
|Net cash used in investing activities|(34,844,794)|(53,709,928)|
|CASH FLOWS FROM FINANCING ACTIVITIES|
|Proceeds from issue of shares|80,000,000|62,728,000|
|Payment for share issue costs|(3,412,458)|(2,600,746)|
|Net cash provided by financing activities|76,587,542|60,127,254|
|NET DECREASE IN CASH AND CASH EQUIVALENTS|6,480,608|(14,356,203)|
|Cash and cash equivalents at the beginning of the year|46,978,179|60,670,897|
|Effects of exchange rate changes on cash and cash equivalents|(3,531,991)|663,485|
|Cash and cash equivalents at the end of the financial year|20(a)|49,926,796|46,978,179|

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Notes to the financial statements are included on pages 50 to 77.

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2017 FAR Annual Report

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

1. GENERAL INFORMATION

FAR Ltd (the ‘Company’) is an Australian listed public company, incorporated in Australia and operating in Africa and Australia. The principal activities of the Company and its subsidiaries (the ‘Group’) are disclosed in the Directors Report.

FAR Ltd’s registered office and its principal place of business at the date of this report is as follows:

Level 17, 530 Collins Street Melbourne VIC 3000 Tel: (03) 9618 2550

2. ADOPTION OF NEW AND REVISED ACCOUNTING STANDARDS

In the current period, the Group has adopted all of the new and revised Standards and Interpretations issued by the Australian Accounting Standards Board (the ‘AASB’) that are relevant to its operations and effective for reporting periods beginning on 1 January 2017.

The Group has not elected to early adopt any new standards or amendments.

The directors note that the expected impact of the Revenue from Contracts with Customers and the Financial Instrument Accounting Standards is not considered material. The Group is currently evaluating the impact of the new Leases Standard.

At the date of authorisation of the financial statements, the Standards and Interpretations that were issued but not yet effective are listed below.

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|||||
|---|---|---|---|
|Effective|
|AASB 9|Financial Instruments, and the relevant amending standards|1 Jan 2018|
|AASB 15|Revenue from Contracts with Customers|, AASB 2014-5|Amendments to Australian Accounting|
|Standards arising from|AASB 15, AASB 2015-8|Amendments to Australian Accounting Standards –|
|Effective Date of AASB 15|, and AASB 2016-3|Amendments to Australian Accounting Standards –|
|Clarifications to AASB 15|1 Jan 2018|
|AASB 16|Leases|1 Jan 2019|
|AASB 2014-10|Amendments to Australian Accounting Standards – Sale or Contribution of Assets between|
|an Investor and its Associate or Joint Venture|and AASB 2015-10|Amendments to Australian Accounting|
|Standards – Effective Date of Amendments to AASB 10 and AASB 128|1 Jan 2018|
|–|
|AASB 2016-5 Amendments to Australian Accounting Standards|Classification and Measurement of|
|Share-based Payment Transactions|1 Jan 2018|
|AASB Interpretation 22 F|oreign Currency Transactions and Advance Consideration|1 Jan 2018|

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At the date of authorisation of the financial statements, the following IASB Standards and IFRIC Interpretations were also in issue but not yet effective, although Australian equivalent Standards and Interpretations have not yet been issued.

none

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3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Statement of compliance

The financial report is a general purpose financial report which has been prepared in accordance with the Corporations Act 2001, Accounting Standards and Interpretations, and complies with other requirements of the law. The financial report comprises the consolidated financial statements of the Group. For the purposes of preparing the consolidated financial statements, the Company is a for profit entity.

Accounting Standards include Australian Accounting Standards. Compliance with Australian Accounting Standards ensures that the financial statements and notes of the Group comply with International Financial Reporting Standards (‘IFRS’).

The financial statements were authorised for issue by the directors on 20 March 2018.

(b) Basis of preparation

The consolidated financial statements have been prepared on the basis of historical cost, except for the revaluation of certain financial instruments that are measured at fair values, as explained in the accounting policies below. Cost is based on the fair values of the consideration given in exchange for assets.

The following significant accounting policies have been adopted in the preparation and presentation of the financial report:

(c) Basis of consolidation

The consolidated financial statements incorporate the financial statements of the Company and entities (including structured entities) controlled by the Company and its subsidiaries (referred to as ‘the Group’ in these financial statements). Control is achieved when the Company:

has power over the investee;
is exposed, or has rights, to variable returns from its involvement with the investee; and
has the ability to use its power to affect the returns.

The company reassesses whether or not it controls an investee if facts and circumstances indicate that there are changes to one or more of the three elements of control listed above.

Consolidation of a subsidiary begins when the Company obtains control over the subsidiary and ceases when the Company loses control of the subsidiary. Income and expenses of a subsidiary acquired or disposed of during the year are included in the consolidated statement of profit or loss and other comprehensive income from the date the Company gains control until the date when the Company ceases to control the subsidiary.

(d) Going concern

The Directors believe that it is appropriate to prepare the consolidated financial statements on a going concern basis. As at 31 December 2017, the Group’s current assets exceeded current liabilities by $42,603,925 and the Group has cash and cash equivalents of $49,926,796. The Group will continue to manage its evaluation and operating activities and put in place financing arrangements to ensure that it has sufficient cash reserves for the next twelve months. The Group will likely require funding within the next twelve months to fund future development Operations in Senegal (where a development

plan is expected to be submitted to the Government of Senegal during 2018), and exploration Operations in The Gambia, Guinea Bissau, Australia and any new exploration blocks the Company may acquire. For further details of future commitments refer to Note 16. In the opinion of the Directors, the Group will be in a position to continue to meet its liabilities and obligations for a period of at least twelve months from the date of this report, and the Company believes it has adequate plans in place to be able to secure funding for its planned activities over the same period.

The opinion of the Directors has been determined after consideration of the Company’s cash position and forecast expenditures and having regard for the following factors:

The ability to issue share capital under the Corporations Act 2001, if required, by a share purchase plan, share placement or rights issue;
The option of farming out all or part of the Group’s assets;
The option of selling interests in the Group’s assets;
The option of relinquishing or disposing of rights and interests in certain assets; and
The ability to raise debt funding.

The Directors are satisfied that the Company will be able to realise its assets and discharge its liabilities in the normal course of business. Uncertainty exists as to the result of the Group’s exploration activities, access to funds and the realisation of the current value of its assets. Consequently, the Directors regularly assess the Company’s and the Group’s status as a going concern and its changing risk profile as circumstances change.

(e) Cash and cash equivalents

Cash and cash equivalents includes cash on hand, deposits held at call with financial institutions and other short-term, highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes on value, net of outstanding bank overdrafts.

(f) Fair value estimation

In estimating fair value of an asset or liability, the group takes into account the characteristics of the asset or liability if market participants would take those characteristics into account when pricing the asset or liability at the measurement date. Fair value for measurement and/or disclosure purposes in these consolidated financial statements is determined on such a basis, except for share-based payment transactions that are within the scope of AASB 2, leasing transactions that are within the scope of AASB 117, and measurements that have some similarities to fair value but are not fair value, such as net realisable value in AASB 2 or value in use in AASB 136.

In addition, for financial reporting purposes, fair value measurements are categorised into level 1, 2 or 3 based on the degree to which the inputs to the fair value measurements are observable and the significance of the inputs to the fair value measurement in its entirety, which are described as follows:

Level 1 inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities that the entity can access at the measurement date;

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2017 FAR Annual Report

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

Level 2 inputs are inputs, other than quoted prices included in Level 1, that are observable for the asset or liability, either directly or indirectly; and
Level 3 inputs are unobservable inputs for the asset or liability.

(g) Employee benefits

Short and long term employee benefits

A liability is recognised for benefits accruing to employees in respect of wages and salaries, annual leave and sick leave in the period the related service is rendered. Liabilities recognised in respect of short-term employee benefits, are measured at their nominal values using the remuneration rate expected to apply at the time of settlement. Liabilities recognised in respect of long term employee benefits are measured at the present value of the estimated future cash outflows to be made by the Group in respect of services provided by employees up to reporting date.

Termination benefits

Where contractual arrangements provide for a payment to a director or employee on termination of their employment, a provision for the payment of such amounts is recognised as the obligation arises.

(h) Financial assets

Financial assets at fair value through profit or loss A financial asset is classified in this category when the asset is either held for trading or it is designated as at fair value through profit or loss. Financial assets held for trading purposes are classified as current assets and are stated at fair value, with any resultant gain or loss recognised in profit or loss.

Held-to-maturity investments

Held-to-maturity investments are non-derivative financial assets with fixed or determinable payments and fixed maturities that the Group’s management has the positive intention and ability to hold to maturity and are initially held at fair value net of transactions costs.

Bills of exchange classified as held to maturity are recorded at amortised cost using the effective interest method less impairment, with revenue recognised on an effective yield basis.

Loans and receivables

Loans and receivables are included in receivables in the statement of financial position. Loans and receivables are recorded at amortised cost using the effective interest method, less any impairment.

Impairment of financial assets

Financial assets are assessed for indicators of impairment at each Statement of Financial Position date. Financial assets are impaired where there is objective evidence that as a result of one or more events that occurred after the initial recognition of the financial asset the estimated future cash flows of the investment have been impacted.

For financial assets carried at amortised cost, the amount of the impairment is the difference between the asset’s carrying amount and the present value of estimated future cash flows, discounted at the original effective interest rate.

The carrying amount of financial assets including uncollectible trade receivables is reduced by the impairment loss through the use of an allowance account. Subsequent recoveries of amounts previously written off are credited against the allowance account. Changes in the carrying amount of the allowance account are recognised in profit or loss.

(i) Financial instruments

Transaction costs on the issue of equity instruments Transaction costs arising on the issue of equity instruments, including new shares and options, are recognised directly in equity as a reduction of the proceeds of the equity instruments to which the costs relate.

Financial liabilities

Financial liabilities are classified as either financial liabilities ‘at fair value through profit or loss’ or other financial liabilities.

Financial liabilities at fair value through profit or loss Financial liabilities at fair value through profit or loss are stated at fair value, with any resultant gain or loss recognised in profit or loss. The net gain or loss recognised in profit or loss incorporates any interest paid on the financial liability. Fair value is determined in the manner described in Note 3(f).

Other financial liabilities

Other financial liabilities are initially measured at fair value, net of transaction costs.

Other financial liabilities are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis.

(j) Provisions

Provisions are recognised when the Group has a present obligation as a result of a past event, the future sacrifice of economic benefits is probable, and the amount of the provision can be measured reliably.

The amount recognised as a provision is the best estimate of the consideration required to settle the present obligation at reporting date, taking into account the risks and uncertainties surrounding the obligation. Where a provision is measured using the cash flows estimated to settle the present obligation, its carrying amount is the present value of those cash flows. When some or all of the economic benefits required to settle a provision are expected to be recovered from a third party, the receivable is recognised as an asset if it is virtually certain that recovery will be received and the amount of the receivable can be measured reliably.

(k) Foreign currency translation

Functional and presentation currency

Items included in the financial statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the Entity operates (‘the functional currency’).

The Consolidated financial statements are presented in Australian dollars, which is FAR Ltd’s functional and presentation currency.

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Transactions and balances

Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at year-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognised in the statement of profit or loss and other comprehensive income.

Group companies and foreign operations

The results and financial position of all the Group entities (none of which has the currency of a hyperinflationary economy) that have a functional currency different from the presentation currency are translated into the presentation currency as follows:

Assets and liabilities are translated at the closing rate at the date of that statement of financial position;
Income and expenses are translated at average exchange rates (unless this is not a reasonable approximation of the cumulative effect of the rates prevailing on the transaction dates, in which case income and expenses are translated at the dates of the transactions); and
All resulting exchange differences are recognised in other comprehensive income as a separate component of equity.

(l) Income tax

Current tax

Current tax is calculated by reference to the amount of income taxes payable or recoverable in respect of the taxable profit or tax loss for the period. It is calculated using tax rates and tax laws that have been enacted or substantively enacted by reporting date. Current tax for current and prior periods is recognised as a liability (or asset) to the extent that it is unpaid (or refundable).

Deferred tax

Deferred tax is accounted for using the balance sheet liability method in respect of temporary differences arising from differences between the carrying amount of assets and liabilities in the financial statements and the corresponding tax base of those items.

In principle, deferred tax liabilities are recognised for all taxable temporary differences. Deferred tax assets are recognised to the extent that it is probable that sufficient taxable amounts will be available against which deductible temporary differences or unused tax losses and tax offsets can be utilised. However, deferred tax assets and liabilities are not recognised if the temporary differences giving rise to them arise from the initial recognition of assets and liabilities (other than as a result of a business combination) which affects neither taxable income nor accounting profit.

Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and joint ventures except where the Group is able to control the reversal of the temporary differences and it is probable that the temporary differences will not reverse in the foreseeable future.

Deferred tax assets arising from deductible temporary differences associated with these investments and interests are only recognised to the extent that it is probable that there will be sufficient taxable profits against which to utilise the benefits of the temporary differences and they are expected to reverse in the foreseeable future.

Deferred tax assets and liabilities are measured at the tax rates that are expected to apply to the period(s) when the asset and liability giving rise to them are realised or settled, based on tax rates (and tax laws) that have been enacted or substantively enacted by reporting date. The measurement of deferred tax liabilities and assets reflects the tax consequences that would follow from the manner in which the Group expects, at the reporting date, to recover or settle the carrying amount of its assets and liabilities.

Deferred tax assets and liabilities are offset when they relate to income taxes levied by the same taxation authority and the Company/Group intends to settle its current tax assets and liabilities on a net basis.

Tax consolidation

The Company and all its wholly-owned Australian resident Entities are part of a tax consolidated group under Australian taxation law. FAR Ltd is the Head Entity in the tax consolidated group. A tax funding arrangement has not been finalised between Entities within the tax consolidated group. Tax expense/income, deferred tax liabilities and deferred tax assets arising from temporary differences of the members of the tax consolidated group are recognised in the separate financial statements of the members of the tax consolidated group using the ‘stand-alone taxpayer’ approach by reference to the carrying amounts in the separate financial statements of each entity and the tax values applying under tax consolidation. Current tax liabilities and assets and deferred tax assets arising from unused tax losses and relevant tax credits of the members of the tax consolidated group are recognised by the Company (as Head-Entity in the tax consolidated group).

(m) Interest in joint operations

A joint operation is a joint arrangement whereby the parties that have joint control of the arrangement have rights to the assets, and obligations for the liabilities, relating to the arrangement. Joint control is the contractually agreed sharing of control of an arrangement, which exists only when decisions about the relevant activities require the unanimous consent of the parties sharing control.

Under certain agreements, more than one combination of participants can make decisions about the relevant activities and therefore joint control does not exist. Where the arrangement has the same legal form as a joint operation but is not subject to joint control, the group accounts for its interest in accordance with the contractual agreement by recognising its share of jointly held assets, liabilities, revenues and expenses of the arrangement.

When a Group entity undertakes its activities under joint operations, the Group as a joint operator recognises in relation to its interest in a joint operation:

Its assets, including its share of any assets jointly held;
Its liabilities, including its share of any liabilities incurred jointly;
Its revenue from the sale of its share of the output arising from the joint operation;
Its share of the revenue from the sale of the output by the joint operation; and
Its expenses, including its share of any expenses incurred jointly.

2017 FAR Annual Report

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

The Group accounts for its assets, liabilities, revenues and expenses relating to its interest in a joint operation in accordance with the AASBs applicable to the particular assets, liabilities, revenues and expenses.

When a Group entity transacts with a joint operation in which a Group entity is a joint operator (such as a sale or contribution of assets), the Group is considered to be conducting the transaction with the other parties to the joint operation, and gains and losses resulting from the transactions are recognised in the Group’s consolidated financial statements only to the extent of other parties’ interests in the joint operation.

When a Group entity transacts with a joint operation in which a Group entity is a joint operator (such as a purchase of assets), the Group does not recognise its share of the gains and losses until it resells those assets to a third party.

(n) Leases

Operating lease payments are recognised as an expense on a straight-line basis over the lease term, except where another systematic basis is more representative of the time pattern in which economic benefits from the leased asset are consumed.

(o) Revenue recognition

Interest revenue

Interest revenue is recognised on a time proportionate basis that takes into account the effective yield on the financial asset.

(p) Exploration and evaluation costs

The Group’s policy is based on the petroleum industry’s ‘successful efforts’ approach to accounting.

The Group expenses exploration and evaluation expenditures except in relation to drilling costs, delineation seismic and other costs directly attributable to defining specific geological targets which are capitalised subject to the determination of commerciality of the geological target under evaluation.

In accordance with the above policy and AASB 6 ‘Exploration for and Evaluation of Mineral Resources’, capitalised exploration and evaluation costs in respect of each ‘area of interest’ or geographical segment are disclosed as a separate class of assets. Costs are partially or fully capitalised as an exploration and evaluation asset provided exploration titles are current and at least one of the following conditions are satisfied:

(i) the exploration and evaluation expenditures are expected to be recouped through development and exploitation of the area of interest or by future sale; or
(ii) exploration and evaluation activities in the area of interest have not at the reporting date reached a stage which permits a reasonable assessment of the existence or otherwise of economically recoverable reserves, and active and significant operations in, or in relation to, the area of interest are continuing.

Exploration and evaluation assets are classified between tangible and intangible and are assessed for impairment when facts and circumstances suggest the carrying amount may exceed the recoverable amount. Impairment losses are recognised in the statement of profit or loss and other comprehensive income.

Employee benefit costs directly attributable to exploration and evaluation projects are recharged from the employee benefit expense to either exploration costs or exploration and evaluation assets.

(q) Property, plant and equipment

Plant and equipment are stated at cost less accumulated depreciation and impairment. Cost includes expenditure that is directly attributable to the acquisition of the item. Subsequent costs are included in the asset’s carrying amount or recognised as a separate asset, as appropriate, only when it is probable that future economic benefits associated with the item will flow to the Group and the cost of the item can be measured reliably. All other repairs and maintenance are charged to the statement of profit or loss and other comprehensive income during the financial period in which they are incurred.

All tangible assets have limited useful lives and are depreciated using the diminishing value method over their estimated useful lives, taking into account estimated residual values, to write off the cost to its estimated residual value, as follows:

Furniture, fittings and equipment: 10-40%

Leasehold improvements are depreciated over the period of the lease or estimated useful life, whichever is the shorter, using the diminishing value method.

The estimated useful lives, residual values and depreciation method are reviewed at the end of each annual reporting period and adjusted if appropriate.

(r) Impairment of assets

At each reporting date the group reviews the carrying amounts of its assets to determine whether there is any indication that those assets have suffered an impairment loss. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment loss (if any). Where the asset does not generate cash flows that are independent from other assets, the group estimates the recoverable amount of the cash-generating unit to which the asset belongs. Where a reasonable and consistent basis of allocation can be identified, corporate assets are also allocated to individual cash-generating units or otherwise they are allocated to the smallest group of cash-generating units for which a reasonable and consistent allocation basis can be identified.

Intangible assets with indefinite useful lives and intangible assets not yet available for use are tested for impairment annually and whenever there is an indication that the asset may be impaired. Recoverable amount is the higher of fair value less costs to sell and value in use. In assessing value in use, the estimated future cash flows are discounted to their present value using a pre-tax discount rate that reflects current market assessments of the time value of money and the risks specific to the asset for which the estimates of future cash flows have not been adjusted.

If the recoverable amount of an asset (or cash-generating unit) is estimated to be less than its carrying amount, the carrying amount of the asset (or cash-generating unit) is reduced to its recoverable amount. An impairment loss is recognised immediately in profit or loss.

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Where an impairment loss subsequently reverses, the carrying amount of the asset (or cash-generating unit) is increased to the revised estimate of its recoverable amount but only to the extent that the increased carrying amount does not exceed the carrying amount that would have been determined had no impairment loss been recognised for the asset (or cash-generating unit) in prior years. A reversal of an impairment loss is recognised immediately in profit or loss.

(s) Share-based payments

Equity-settled share-based payments with employees and others providing similar services are measured at the fair value of the equity instruments at the grant date. Details on how the fair value of equity-settled share-based transactions has been determined can be found in Note 22.

The fair value determined at the grant date of the equity-settled share-based payments is expensed on a straight-line basis over the vesting period, based on the Group’s estimate of shares that will eventually vest, with a corresponding increase in equity. At the end of each reporting period, the Group revises its estimate of the number of equity instruments expected to vest. The impact of the revision of the original estimates, if any, is recognised in profit or loss such that the cumulative expense reflects the revised estimate, with a corresponding adjustment to the equitysettled employee benefits reserve.

Equity-settled share-based payment transactions with other parties are measured at the fair value of the goods and services received, except where the fair value cannot be estimated reliably, in which case they are measured at the fair value of the equity instruments granted, measured at the date the entity obtains the goods or the counterparty renders the service.

4. CRITICAL ACCOUNTING JUDGEMENTS AND KEY SOURCES OF ESTIMATION UNCERTAINTY

In the application of the Group’s accounting policies, which are described in Note 3, management is required to make judgments, estimates and assumptions about carrying values of assets and liabilities that are not readily apparent from other sources. The estimates and associated assumptions are based on historical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the basis of making the judgments. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period, or in the period of the revision and future periods if the revision affects both current and future periods.

Critical judgements in applying the Entity’s accounting policies

The following critical judgement, including estimations, that management has made in the process of applying the Group’s accounting policies and that had the most significant effect on the amounts recognised in the financial statements:

(i) The Group has capitalised significant exploration and evaluation expenditure on the basis either that this is expected to be recouped through future successful development or alternatively sale of the areas of interest. If, ultimately, the areas of interest are abandoned or are not successfully commercialised, the carrying value of the capitalised exploration and evaluation expenditure would need to be written down to its recoverable amount.

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2017 FAR Annual Report 55

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

5. SEGMENT INFORMATION

AASB 8 ‘Operating Segments’ requires operating segments to be identified on the basis of internal reports about components of the entity that are regularly reviewed by the Managing Director (chief operating decision maker) in order to allocate resources to the segments and to assess its performance.

The Group undertook exploration for oil and gas in Australia and Africa during the year.

Segment Assets and Liabilities

The following is an analysis of the Group’s assets and liabilities by reportable operating segment:

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||||||
|---|---|---|---|---|
|Assets|Liabilities|
|Year ended|Year ended|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|31 Dec 2017|31 Dec 2016|
|AU$|AU$|AU$|AU$|
|The Gambia|10,139,222|-|597,600|-|
|Guinea-Bissau|1,168,431|1,278,206|30,150|18,765|
|Kenya|308,155|1,176,802|6,863|16,389|
|Senegal|120,630,687|102,561,602|7,610,239|5,392,889|
|Other|8,842|9,536|14,347|4,773|
|Corporate|49,037,297|46,674,229|1,445,864|1,467,334|
|Total assets and liabilities|181,292,634|151,700,375|9,705,063|6,900,150|

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Segment Revenue and Results

The following is an analysis of the Group’s revenue and results from operations:

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||||||
|---|---|---|---|---|
|Interest Income|Segment Loss|
|Year ended|Year ended|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|31 Dec 2017|31 Dec 2016|
|AU$|AU$|AU$|AU$|
|Australia|-|-|(48,488)|(957,104)|
|The Gambia|-|-|(7,055,678)|-|
|Guinea-Bissau|-|-|(985,968)|(1,085,706)|
|-|-|
|Kenya|(568,964)|(341,388)|
|-|-|
|Senegal|(26,106,643)|(13,452,226)|
|Other|-|302|(434,487)|(520,727)|
|Corporate|614,149|165,475|(7,578,952)|(5,402,823)|
|Total for continuing operations|614,149|165,777|(42,779,180)|(21,759,974)|
|-|-|
|Income tax expense|
|Loss before tax (continuing operations)|(42,779,180)|(21,759,974)|

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The revenue reported above represents revenue generated from external sources. There were no intersegment sales during the year.

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Other Segment Information

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|||||||
|---|---|---|---|---|---|
|Depreciation and Amortisation|Additions to Non-Current Assets|
|Year ended|Year ended|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|31 Dec 2017|31 Dec 2016|
|AU$|AU$|AU$|AU$|
|The Gambia|-|-|10,139,221|-|
|Guinea-Bissau|-|-|31,565|(355,336)|[(i)]|
|-|-|-|
|Kenya|1,655|
|-|-|
|Senegal|24,758,534|42,637,856|
|Corporate|40,330|41,033|57,206|56,207|
|Total|40,330|41,033|34,986,526|42,340,382|

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(i) Reflects a credit for long lead items previously capitalised to drilling costs under a historical escrow arrangement

6. PROFIT/LOSS FOR THE YEAR

Loss for the year from continuing operations includes the following expenses:

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||||
|---|---|---|
|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Depreciation and amortisation:|
|- Property, plant & equipment|(83,914)|(82,926)|
|- Less reallocation to exploration expense|43,584|41,893|
|-|-|
|- Amortisation of goodwill on acquisition of subsidiary|
|(40,330)|(41,033)|
|Exploration Expense:|
|- Australia|(48,488)|(957,104)|
|- The Gambia|(7,055,678)|-|
|- Guinea-Bissau|(985,968)|(1,085,706)|
|- Senegal|(26,106,643)|(13,452,226)|
|- Kenya|(568,964)|(341,388)|
|- Other|(434,486)|(515,981)|
|(35,200,227)|(16,352,405)|
|Operating lease rental expenses:|
|- Rental expense on operating lease|(142,874)|(148,904)|
|Post-employment benefits:|
|- Remuneration expense|(3,142,136)|(2,871,556)|
|-|
|- Termination payment|(470,138)|
|- Recharge of remuneration expense to exploration expense|1,183,067|1,101,010|
|Post employment benefits:|
|- superannuation contributions|(197,441)|(196,188)|
|- amortisation of performance rights and options|(446,169)|(2,490,223)|
|- provision for leave entitlements|(193,921)|(155,466)|
|(3,266,738)|(4,612,423)|

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2017 FAR Annual Report 57

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

7. INCOME TAXES

(a) Income tax recognised in profit or loss

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||||
|---|---|---|
|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Tax (income) comprises:|
|Current tax expense|(1,490,070)|(1,156,857)|
|Tax losses not brought to account|1,490,070|1,156,857|
|Deferred tax (income) relating to the origination and reversal of temporary differences|323,397|(49,444)|
|Benefit arising from previously recognised tax losses of prior periods used to reduce|
|deferred tax expense|(323,397)|49,444|
|Prior year unders / overs|417,281|522,734|
|Utilisation of previously unrecognised tax losses|(417,281)|(522,734)|
|-|-|
|Total tax expense / (income)|

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The prima facie income tax expense on pre-tax accounting profit from operations reconciles to the income tax expense in the financial statements as follows:

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||||
|---|---|---|
|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Loss from operations|(42,779,180)|(21,759,974)|
|Income tax (income) calculated at 30%|(12,833,754)|(6,527,992)|
|Non-deductible expenses|11,826,770|5,398,346|
|-|
|Non-assessable gains / (loss)|267,508|
|Recognition of previously unrecognised deductible temporary differences|(483,086)|(294,719)|
|Unused tax losses and tax offsets not recognised as deferred tax assets|1,490,070|1,156,857|
|-|-|

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The tax rate used in the above reconciliation is the corporate tax rate of 30% payable by Australian corporate entities on taxable profits under Australian tax law. There has been no change in the corporate tax rate when compared with the previous reporting period. No adjustment has been made for the incremental impact of the USA federal income tax rate which is marginally higher at 35% for the purpose of this disclosure note as the impact is not considered significant with respect to the operations of the Group.

(b) Income tax recognised directly in equity

There were no current and deferred amounts charged directly to equity during the period.

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(c) Deferred tax balances

Taxable and deductible temporary differences arise from the following:

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|||||
|---|---|---|---|
|Recognised|Closing|
|Opening balance|in income|balance|
|2017|AU$|AU$|AU$|
|Property, plant & equipment|(453)|(20,551)|(21,004)|
|Receivables|(494,228)|281,665|(212,563)|
|Payables|19,158|4,107|23,265|
|Provisions|282,432|58,176|340,608|
|Total|(193,091)|323,397|130,306|

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|||||
|---|---|---|---|
|Recognised|Closing|
|Opening balance|in income|balance|
|2016|AU$|AU$|AU$|
|Property, plant & equipment|(495)|42|(453)|
|Receivables|(397,522)|(96,706)|(494,228)|
|Payables|18,578|580|19,158|
|Provisions|235,792|46,640|282,432|
|Total|(143,647)|(49,444)|(193,091)|

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Unrecognised deferred tax balances|
|The following deferred tax assets have not been brought to account as assets:|
|-|
|Deferred tax assets on temporary differences (net)|130,306|
|Tax losses in the United States (net)|4,388,161|4,730,863|
|Tax losses in Australia (net)|16,396,521|14,489,170|
|Capital losses in Australia|99,257|99,257|
|21,014,245|19,319,290|

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Tax consolidation

Relevance of tax consolidation to the Group

The Company and its wholly-owned Australian resident entities have formed a tax consolidated group with effect from 1 July 2007 and are therefore taxed as a single entity from that date. The Head Entity within the tax consolidated group is FAR Ltd. The members of the tax consolidated group are identified at Note 19.

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2017 FAR Annual Report 59

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

8. TRADE AND OTHER RECEIVABLES

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|||||
|---|---|---|---|
|31 Dec 2017|31 Dec 2016|
|Current|AU$|AU$|
|Interest receivable|25,281|9,806|
|Other receivables|1,338,588|749,255|
|Prepayments|657,304|177,377|
|Joint venture receivables|[ (i)]|127,152|1,639,226|
|2,148,325|2,575,664|

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(i) Includes Senegal joint operation receivables of $nil (2016: $1,494,224).

The credit period of oil and gas varies between 30 and 60 days. No trade receivable were past due at balance date.

9. OTHER FINANCIAL ASSETS

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|Current|AU$|AU$|
|Security deposit|1,521|1,640|
|Joint operation performance bond|121,968|118,659|
|123,489|120,299|

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The weighted average interest rate on the performance bond is 2.42% (2016: 1.88%).

10. PROPERTY, PLANT AND EQUIPMENT

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Furniture, Fittings & Equipment Cost|
|Balance at 1 January|839,344|783,137|
|Additions|126,362|56,207|
|-|
|Net foreign currency exchange differences|(36,423)|
|Balance at 31 December|929,283|839,344|
|Accumulated depreciation and impairment|
|Balance at 1 January|519,877|436,951|
|Depreciation expense|83,916|82,926|
|-|
|Disposals|(33,890)|
|Balance at 31 December|569,903|519,877|
|Net Book Value|359,380|319,467|

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11. EXPLORATION AND EVALUATION ASSETS

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|||||
|---|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Exploration and evaluation expenditure:|101,706,766|58,861,246|
|Balance at 1 January|
|Additions|[ (i)]|34,860,163|42,284,176|
|-|
|Impairment|[ (ii)]|(463,231)|
|Net foreign currency exchange differences|[ (iii)]|(7,369,054)|561,344|
|Balance at 31 December|128,734,644|101,706,766|

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(i) Additions during the year include the Senegal capitalised well costs for SNE-5, VR-1, SNE-6 and SNE North of $24,758,534. Also included in additions are the acquisition costs of an 80% interest in The Gambia Blocks A2 and A5 plus drilling long lead items and other drilling costs of $10,070,065.

(ii) The Kenya L6 capitalised drilling costs have been impaired in full.

(iii) Included in net foreign currency exchange difference is a negative amount of $7,268,410 relating to the revaluation of the opening balance of the prior years capitalised Senegal well costs.

12. TRADE AND OTHER PAYABLES

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|||||
|---|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Current|
|Trade payables|[ (i)]|553,401|405,936|
|Other payables|392,381|287,615|
|Joint venture payables|[ (ii)]|7,623,918|5,265,158|
|8,569,700|5,958,709|

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(i) The average credit period on purchases is approximately 30 days. No interest is charged on the trade payables for the first 30 days from the date of the invoice. Thereafter, interest may be levied on the outstanding balance at varying rates. The Group has financial risk management policies in place to ensure that payables are paid within the credit timeframe.

(ii) Includes FAR’s share of Senegal joint operation payables and accruals of $7,267,294 (2016: $5,205,756) relating to the Senegal wells SNE-2, SNE-3, BEL-1, planning and preparation costs of SNE-5 and SNE-6 and other costs.

13. PROVISIONS

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|||||
|---|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Current|
|Employee benefits|[ (i)]|1,024,985|885,571|
|Non-Current|
|Employee benefits|110,378|55,870|

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(i) The above provisions for employee benefits represent annual leave and long service leave entitlements accrued by employees.

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2017 FAR Annual Report 61

NOTES TO THE FINANCIAL STATEMENTS For the financial year ended 31 December 2017

14. ISSUED CAPITAL

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|||||||
|---|---|---|---|---|---|
|31 Dec 2017|31 Dec 2017|31 Dec 2016|31 Dec 2016|
|Number|AU$|Number|AU$|
|Paid up capital:|
|Ordinary fully paid shares|
|at beginning of year|4,461,532,458|297,933,534|3,693,650,099|237,806,280|
|Shares allotted during the year|[ (a)]|1,000,000,000|80,000,000|767,882,359|62,728,000|
|Share issue costs|-|(3,412,458)|-|(2,600,746)|
|Ordinary fully paid shares at end of year|5,461,532,458|374,521,076|4,461,532,458|297,933,534|

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Fully paid ordinary shares carry one vote per share and carry a right to dividends.

(a) The following share issues were made during the year:
(i) 669,229,868 ordinary fully paid shares were issued at 8.0 cents per share via a placement to institutional and sophisticated investors on 12 April 2017.
(ii) 330,770,132 ordinary fully paid shares were issued at 8.0 cents per share via a placement to institutional and sophisticated investors on 19 May 2017.

Share options outstanding at balance date

See Note 22 share based payments for details of options and performance rights outstanding at 31 December 2017.

15. EARNINGS PER SHARE

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|Cents per share|Cents per share|
|Basic loss per share|
|From continuing operations|(0.83)|(0.52)|
|Diluted loss per share|
|From continuing operations|(0.83)|(0.52)|

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Basic and diluted loss per share

The earnings and weighted average number of ordinary shares used in the calculation of basic and diluted earnings per share are as follows:

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||||
|---|---|---|
|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Loss:|
|Loss for the year attributable to members of FAR Ltd|(42,779,180)|(21,759,974)|
|Number|Number|
|Weighted average number of ordinary shares for the purposes of basic|
|and diluted loss per share|5,139,066,630|4,207,584,889|

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The following potential ordinary shares are not dilutive and are therefore excluded from the weighted average number of ordinary shares used in the calculation of diluted EPS:

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|Number|Number|
|10.0 cents, June 2018, unlisted options|60,000,000|68,000,000|
|0.0 cents, January 2021, unlisted performance rights|18,497,000|21,425,000|
|-|
|0.0 cents, January 2022, unlisted performance rights|10,837,000|
|89,334,000|89,425,000|

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16. COMMITMENTS FOR EXPENDITURE

In order to maintain rights to tenure of exploration permits, the Group is required to perform minimum work programs specified by various state and national governments. These obligations are subject to renegotiation in certain circumstances such as when an application for an extension permit is made or at other times. The minimum work program commitments may be reduced by the Group by entering into sale or farm-out agreements or by relinquishing permit interests. Should the minimum work program not be completed in full or in part in respect of a permit then the Group’s interest in that exploration permit could either be reduced or forfeited. In some instances a financial penalty

may result if the minimum work program is not completed. Approved expenditure for permits may be in excess of the minimum expenditure or work commitment. Where the Group has a financial obligation in relation to approved joint operation exploration expenditure that is greater than the minimum permit work program commitments then these amounts are also reported as a commitment.

The current estimated expenditures for approved commitments and minimum work program commitments are as follows:

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Exploration and evaluation|
|Not longer than 1 year|47,308,527|45,710,644|
|-|-|
|Longer than 1 year and not longer than 5 years|
|-|-|
|Longer that 5 years|
|47,308,527|45,710,644|

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A substantial portion of the above commitments relate to The Gambia which subject to the completion of the farm-in deal for blocks A2 and A5 to PETRONAS, the National Oil Company of Malaysia will be materially reduced. The farm-in deal with PETRONAS requires PETRONAS to fund 80% of total well costs through an exploration well, Samo-1, up to a maximum total cost of US$45.0 million. For further details, see note 25.

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2017 FAR Annual Report 63

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

17. CONTINGENT LIABILITIES AND CONTINGENT ASSETS

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|||||
|---|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Contingent liabilities|
|Guinea-Bissau – contingent payment from future production|[ (i)]|16,658,167|17,965,727|
|Guinea-Bissau – contingent withholding tax liability|[ (ii)]|727,592|784,704|
|Kenya L6 – Performance Bond|[ (iii)]|121,968|118,659|
|17,507,727|18,869,090|

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(i) In 2009, the Company entered into an Agreement to acquire a 15% participating interest and a 21.42% paying interest in three blocks offshore of Guinea-Bissau. Under the terms of the Agreement, in the event of future production from the blocks the vendor will be entitled to recover up to $17,965,727 (US$13 million) in past exploration costs from the Company’s proceeds from production. Any such recovery will be at a rate of 50% of the Company’s annual net revenue as defined by the Agreement.

(ii) During the year ended 31 December 2009, the Group was advised by the operator of its blocks in Guinea-Bissau that the Joint Operation partners have a contingent withholding tax liability which would become payable in the event of the Joint Operation entering the development phase of the licences. The Group’s share of the estimated contingent liability as at 31 December 2017 is $727,592.

(iii) Flow Energy Pty Ltd (‘Flow’) a wholly owned subsidiary of the Company is a party to the Kenya Offshore Block L6 Production Sharing Contract. Flow Kenya branch is the Contractor for the project and, in accordance with the terms of the Contract, the Contractor must provide security guaranteeing the Contractor’s minimum work and expenditure obligations on or before the commencement of an Exploration Period. This amount represents the Group’s share of the guarantee. The guarantee is payable on written demand where the Contractor is in default under the contract. Where the Contractor meets the minimum work and expenditure obligations of the Exploration Period the security is released. Security deposit equal to the contingent liability of $121,968 is disclosed in current, other financial assets, see Note 9. Flow Energy has also executed a parent company guarantee to the Kenyan Ministry of Energy and Petroleum in respect of Kenya Block L6 for the performance of the minimum work obligations in relation to year 3 of the Second Additional Exploration Period limited to US$728,450.

There are no contingent liabilities arising from service contracts with executives.

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18. JOINT OPERATIONS

The Consolidated Entity has an interest in the following material joint venture operations whose principal activities are oil and gas exploration

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|||||
|---|---|---|---|
|Name|Equity Interest|
|31 Dec 2017|31 Dec 2016|
|%|%|
|Guinea-Bissau|
|Sinapa / Esperança|[ (i)]|21.4|15.0|
|Kenya|
|L6|[ (iI)]|60.0|60.0|
|Senegal|
|Rufisque Offshore / Sangomar Offshore / Sangomar Deep Offshore|15.0|15.0|
|-|-|
|Djiffere Block|[ (iii)]|
|The Gambia|
|Block A2/ Block A5|[ (iv)]|80.0|-|

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(i) In April 2017, negotiations concluded with the national Oil Company of Guinea-Bissau, Petroguin to revise the terms of both the Sinapa and Esperança Licenses to which FAR has interests. Under the revised licence terms, FAR has a 21.42% interest in the permit, an increase from 15% and FAR’s paying interest remains at 21.42%.
(ii) Past security events and continued land access issues have hampered FAR’s ability to progress with approved work program on the strategically preferred onshore portion of Block L6. FAR is working with the Ministry of Petroleum & Mining to find an amicable solution with relevant landowners and other stakeholders to resolve the situation.
(iii) In September 2015, FAR entered into a farm-in option agreement with a subsidiary of Trace Atlantic Oil Ltd (‘Trace’) for the Djiffere Block offshore Senegal. FAR’s obligations under its agreements with Trace in relation to its option have been met and included acquiring new 3D seismic data over the Djiffere Block in late 2015. During the year FAR and Trace have been in negotiations in relation to an amendment to these agreements.
(iv) Pursuant to the terms of a Sales Agreement with Erin Energy, FAR acquired an 80% interest in The Gambia Blocks A2 and A5 on 29 June 2017.

The Group’s interests in assets employed in the above joint operations are detailed below. The amounts are included in the financial statements under their respective asset and liability categories.

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Current Assets|
|Cash and cash equivalents|3,200,897|1,066,723|
|Trade and other receivables|127,152|1,639,226|
|Other financial assets|123,489|120,299|
|Non-Current Assets|
|-|
|Property, plant and equipment|69,156|
|Exploration and evaluation assets|128,734,644|101,706,766|
|Current Liabilities|
|Trade and other payables|7,623,918|5,265,158|

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Contingent liabilities and capital commitments

The capital commitments arising from the Group’s interests in joint operations are disclosed in Note 16. The contingent liabilities in respect of the Group’s interest in joint operations are disclosed in Note 17.

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2017 FAR Annual Report 65

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

19. SUBSIDIARIES

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||||||
|---|---|---|---|---|
|Ownership interest|
|Country of|2017|2016|
|Name of Entity|incorporation|%|%|
|Parent Entity|
|FAR Ltd|[ (i)]|Australia|
|Subsidiaries|
|First Australian Resources Pty Ltd|[ (ii) (iii)]|Australia|100|100|
|Humanot Pty Ltd|[ (ii) (iii)]|Australia|100|100|
|Flow Energy Pty Ltd|[ (ii) ]|Australia|100|100|
|Neptune Exploration Pty Ltd|[ (ii)]|Australia|100|100|
|Lightmark Enterprises Pty Ltd|[ (ii) ]|Australia|100|100|
|FAR Holdings 1 Pty Ltd|[ (ii)]|Australia|100|100|
|FAR Holdings 2 Pty Ltd|[ (ii)]|Australia|100|100|
|FAR Meridian Pty Ltd|[ (ii)]|Australia|100|100|
|First Australian Resources, Inc.|USA|100|100|
|Petrole Investments Group Pty Ltd|Mauritius|100|100|
|FAR Gambia Ltd|[ (iv)]|Mauritius|100|100|
|FAR Mauritius 1 Pty Ltd|Mauritius|100|100|
|FAR Mauritius 2 Pty Ltd|Mauritius|100|100|
|FAR Guinea Bissau|Mauritius|100|0|
|FAR Kenya L6|Mauritius|100|0|
|FAR Senegal SARL|Senegal|100|100|
|FAR Senegal RSSD SA|Senegal|100|100|
|FAR Senegal 1 SA|Senegal|100|100|
|FAR Senegal Djiffere SA|Senegal|100|100|

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(i) FAR Limited is the Head Entity within the tax consolidated group.

(ii) These companies are members of the tax consolidated group.

(iii) These wholly-owned controlled Entities have entered into a deed of cross guarantee with FAR Ltd pursuant to ASIC Class Order 98/1418 and are relieved from the requirements to prepare and lodge an audited financial report.

(iv) During the year Meridian Minerals Limited changed its name to FAR Gambia Ltd.

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The consolidated statement of profit or loss and other comprehensive income and statement of financial position of entities which are party to the deed of cross guarantee are:

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||||
|---|---|---|
|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|
|Statement of profit or loss and other comprehensive income|AU$|AU$|
|Interest income|613,835|165,473|
|Depreciation and amortisation expense|(40,330)|(41,033)|
|Impairment of intercompany loans and investments|(5,966,149)|(1,934,872)|
|Exploration expense|(28,728,559)|(15,053,913)|
|Administration expense|(686,759)|(664,169)|
|Employee benefits expense|(3,266,738)|(4,612,423)|
|Consulting expense|(292,418)|(486,562)|
|Foreign exchange gain|(3,139,034)|740,536|
|Other expenses|(343,134)|(399,088)|
|Loss before income tax|(41,849,286)|(22,286,051)|
|-|-|
|Income tax expense|
|Loss for the year|(41,849,286)|(22,286,051)|
|Other comprehensive loss|
|Items that may be reclassified subsequently to profit or loss|
|Exchange differences arising on translation of foreign operations|(7,717,023)|1,716,094|
|Total comprehensive loss|(49,566,309)|(20,569,957)|

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2017 FAR Annual Report

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

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31 Dec 2017 31 Dec 2016
Statement of Financial Position AU$ AU$
CURRENT ASSETS
Cash and cash equivalents 49,686,816 46,537,066
Trade and other receivables 4,218,087 2,308,162
Total Current Assets 53,904,903 48,845,228
NON CURRENT ASSETS
Trade and other receivables 7,530,424 106,412
Other financial assets 145 132
Property, plant and equipment 290,224 319,467
Exploration and evaluation assets 118,664,578 101,243,535
Total Non-Current Assets 126,485,371 101,669,546
TOTAL ASSETS 180,390,274 150,514,774
CURRENT LIABILITIES
Trade and other payables 8,122,279 5,908,104
Provisions 1,024,985 885,571
Total Current Liabilities 9,147,264 6,793,675
NON-CURRENT LIABILITIES
Provisions 110,378 55,869
Total Non-Current Liabilities 110,378 55,869
TOTAL LIABILITIES 9,257,642 6,849,544
NET ASSETS 171,132,632 143,665,230
EQUITY
Issued capital 374,521,076 297,933,534
Reserves 5,942,817 13,213,671
Accumulated losses (209,331,261) (167,481,975)
TOTAL EQUITY 171,132,632 143,665,230
31 Dec 2017 31 Dec 2016
Accumulated Losses AU$ AU$
Balance at beginning of financial year (167,481,975) (145,195,924)
Net loss (41,849,286) (22,286,051)
Balance at end of financial year (209,331,261) (167,481,975)
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20. NOTES TO THE CASH FLOW STATEMENT

(a) Reconciliation of cash and cash equivalents

For the purposes of the cash flow statement, cash and cash equivalents includes cash on hand and in banks and investments in money market instruments, net of outstanding bank overdrafts. Cash and cash equivalents at the end of the financial year as shown in the consolidated cash flows can be reconciled to the related items in the statement of financial position as follows:

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Cash and cash equivalents|46,725,899|45,911,456|
|Cash and cash equivalents held in joint operations|3,200,897|1,066,723|
|49,926,796|46,978,179|

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(b) Financing facilities

The Group had no external borrowings at 31 December 2017. Further, the Group has not arranged any financing facilities for use in the future.

(c) Cash balances not available for use

Cash and cash equivalents held in joint operations are not available for use by the Group. There are no other restrictions on cash balances at 31 December 2017.

(d) Reconciliation of profit for the period to net cash flows from operating activities

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Loss for the year|(42,779,180)|(21,759,974)|
|Depreciation and amortisation of non-current assets|83,914|82,926|
|Unrealised Foreign exchange (gain)/loss|3,572,514|(786,641)|
|Equity settled share-based payments|446,169|2,490,223|
|-|
|Impairment of exploration asset|429,518|
|Interest income|(614,125)|(165,777)|
|-|
|Loss on sale of property plant and equipments|2,533|
|(Increase) / decrease in assets:|
|Trade and other receivables|(162,252)|308,231|
|Increase / (decrease) in liabilities:|
|Trade and other payables|3,564,848|(1,097,983)|
|Provisions|193,921|155,466|
|Net cash used in operating activities|(35,262,140)|(20,773,529)|

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2017 FAR Annual Report 69

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

21. FINANCIAL INSTRUMENTS

(a) Capital risk management

The Group manages its capital to ensure that it will be able to continue as a going concern and as at 31 December 2017 has no debt. The capital structure of the Group consists of cash and cash equivalents and equity attributable to equity holders of the parent comprising issued capital, reserves and accumulated losses.

(b) Financial risk management objectives

The Group’s management provides services to the business, coordinates access to domestic and international financial markets, and manages the financial risks relating to the operations of the Group.

The Group does not trade or enter into financial instruments, including derivative financial instruments, for speculative purposes. The use of financial derivatives is governed by the Group’s policies approved by the Board of directors.

The Group’s activities expose it primarily to the financial risks of changes in foreign currency exchange rates, interest rates, liquidity risk and commodity price risk. The Group does not presently enter into derivative financial instruments to manage its exposure to interest rate and foreign currency risk.

(c) Categories of financial instruments

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Financial assets|
|Cash and cash equivalents|49,926,796|46,978,179|
|Trade and other receivables – current and non-current|2,148,325|2,575,664|
|Other financial assets – current and non-current|123,489|120,299|
|Total Financial assets|52,198,610|49,674,142|
|Financial liabilities|
|Trade and other payables|8,569,700|5,958,709|

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(d) Foreign currency risk management

Foreign currency risk sensitivity

At the reporting date, if the Australian dollar had increased/ decreased by 10% against the US dollar the Group’s net profit after tax would increase/decrease by $3,218,593.

(f) Liquidity risk management

The Group manages liquidity risk by maintaining adequate reserves, banking facilities and reserve borrowing facilities by continuously monitoring forecast and actual cash flows and matching the maturity profiles of financial assets and liabilities.

(e) Commodity price risk management

The Group does not currently have any projects in production and has no exposure to commodity price fluctuations.

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Liquidity and interest risk tables

The following tables detail the Group’s remaining contractual maturity for its non-derivative financial assets and liabilities. The tables have been prepared based on the undiscounted cash flows expected to be received/paid by the Group.

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Weighted
Maturity
average
effective Less than 1-3 3 month to 1-5 5+
interest rate 1 month months 1 year years years Total
2017 % AU$ AU$ AU$ AU$ AU$ AU$
Financial assets:
- - - - -
Non-interest bearing 6,043,397 6,043,397
Variable interest rate 1.29 36,433,245 - - - - 36,433,245
Fixed interest rate 1.81 9,600,000 121,968 - - - 9,721,968
- - -
52,076,642 121,968 52,198,610
Financial liabilities:
- - - -
Non-interest bearing 8,568,231 1,469 8,569,700
- - -
8,568,231 1,469 8,569,700
2016
Financial assets:
- - - - -
Non-interest bearing 43,507,356 43,507,356
Variable interest rate 0.87% 248,127 - - - - 248,127
Fixed interest rate 1.88% 5,800,000 118,659 - - - 5,918,659
- - -
49,555,483 118,659 49,674,142
Financial liabilities:
- - -
Non-interest bearing 5,946,471 10,769 1,469 5,958,709
- -
5,946,471 10,769 1,469 5,958,709
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(g) Interest rate risk management

The Group is exposed to interest rate risk as it earns interest at floating rates from a portion of its cash and cash equivalents. The Group places a portion of its funds into short term fixed interest deposits which provide short term certainty over the interest rate earned.

Interest rate sensitivity analysis

If the average interest rate during the year had increased/ decreased by 10% the Group’s net profit after tax would increase/decrease by $61,415.

(h) Credit risk management

The Group does not have any significant credit risk exposure to any single counterparty or any group of counterparties having similar characteristics. The credit risk on liquid funds and financial instruments is limited because the counterparties are banks with high credit-ratings assigned by international credit-rating agencies. The carrying amount of financial assets recorded in the financial statements, net of any allowances for losses, represents the Group’s maximum exposure to credit risk.

(i) Fair value of financial instruments

The directors consider that the carrying amount of financial assets and financial liabilities recorded in the financial statements approximates their fair values (2016: net fair value).

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2017 FAR Annual Report 71

For the financial year ended 31 December 2017

NOTES TO THE FINANCIAL STATEMENTS

22. SHARE-BASED PAYMENTS

(a) Employee share option plan

The shareholders of the Company approved an Executive Incentive Plan at the annual general meeting held on 15 May 2015, prior to then the Company did not have a formal sharebased compensation scheme. In accordance with the provisions of the approved plan, the board at its discretion may grant options to any full-time or permanent part-time employee or officer, or director of the Company to purchase parcels of ordinary shares. All options issued to directors are granted in accordance with a resolution of shareholders.

Each employee option converts into one ordinary share of FAR Ltd on exercise. No amounts are paid or payable by the recipient on receipt of the option. Options may be exercised at the applicable exercise price from the date of vesting to the date of expiry. The options neither carry rights to dividends nor voting rights.

The following share-based payment arrangements were in existence during the current and prior reporting periods:

based compensaton scheme. In accordance with the provisions of the approved plan, the board at its discreton may grant optons to any full-tme or permanent part-tme employee or ofcer, or director of the Company to purchase parcels of ordinary shares. All optons issued to directors are granted in accordance with a resoluton of shareholders. at the applicable exercise price from the date of vestng to the date of expiry. The optons neither carry rights to dividends nor votng rights. The following share-based payment arrangements were in existence during the current and prior reportng periods:
Series 11 Series 10
Grant date 01-Jul-15 21-May-13
Share price at grant date 8.7 cents 2.9 cents
Fair value 4.9 cents 1.6 cents
Expiry date 01-Jun-18 27-May-16
Exercise price 10.0 cents 4.4 cents
Vestng conditons (i) n/a
Number of optons
Balance as at 1 Jan 2017 68,000,000 -
Granted during the year - -
Forfeited during the year (8,000,000) -
Exercised during the year - -
Balance at 31 December 2017 60,000,000 -
Avg. share price at date of exercise n/a n/a

Balance as at 1 Jan 2016 68,000,000 62,000,000
Granted during the year - -
Forfeited during the year - -
Exercised during the year - (62,000,000)
Balance at 31 December 2016 68,000,000 -
Avg. share price at date of exercise n/a 8.8 cents

The options were priced using the black scholes pricing model with the following inputs

The optons were priced using the black scholes pricing model with the following inputs
Series 11 Series 10
Volatlity 95% 97%
Dividend yield - -
Risk free interest rate 2.00% 2.57%
Opton life 2.9 years 3 years

(i) The options vested on 26 October 2016 as determined by the board having satisfied itself the vesting condition of an announcement to the effect of potential economic viability of a future development project by the Operator of the Senegal joint operation was met.

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(b) Employee Performance Rights Plan

The shareholders of the Company approved the Performance Rights Plan at the annual general meeting held on 13 May 2016, prior to then the Company did not have a performance rights plan. In accordance with the provisions of the approved plan, the board at its discretion may grant performance rights to any fulltime or permanent part-time employee or officer, or director

of the Company. All performance rights issued to directors are granted in accordance with a resolution of shareholders. Each Performance Right converts to one Ordinary Share on exercise.

The following share-based payment arrangements were in existence during the current and prior reporting periods:

Rights Plan at the annual general meetng held on 13 May 2016, prior to then the Company did not have a performance rights plan. In accordance with the provisions of the approved plan, the board at its discreton may grant performance rights to any full- tme or permanent part-tme employee or ofcer, or director granted in accordance with a resoluton of shareholders. Each Performance Right converts to one Ordinary Share on exercise. The following share-based payment arrangements were in existence during the current and prior reportng periods:
31 Dec 2017 31 Dec 2016
Grant date 31-May-17 20-May-16
Share price at grant date 7.9 cents 8.7 cents
Base Price 7.8 cents 7.8 cents
Fair value 4.5 cents 5.5 cents
Performance period start date 1-Feb-17 1-Feb-16
Performance period end date 31-Jan-20 31-Jan-19
Expiry date 31-Jan-22 31-Jan-21
Exercise price A$0.0 A$0.0
Number of optons
Balance as at 1 Jan 2017 - 21,425,000
Granted during the year 10,837,000 -
Forfeited during the year - (2,928,000)
Exercised during the year - -
Balance at 31 December 2017 10,837,000 18,497,000
Avg. share price at date of exercise n/a n/a

Balance as at 1 Jan 2016 - -
Granted during the year - 21,425,000
Forfeited during the year - -
Exercised duringthe year - -
Balance at 31 December 2016 - 21,425,000
Avg. shareprice at date of exercise n/a n/a

The performance rights were priced using the Monte Carlo pricing model with the following inputs:

The performance rights were priced using the Monte Carlo pricing model with the following inputs:
31 Dec 2017 31 Dec 2016
Volatlity 47% 60%
Dividend yield - -
Risk free interest rate 1.65% 1.63%
Opton life 2.7 years 2.7 years

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2017 FAR Annual Report 73

The performance rights are subject to the following vesting conditions:

Absolute Total Shareholder Return: a measure of the total shareholder return (share value plus dividends) achieved over the Performance Period; and
Relative Total Shareholder Return: a measure of the total shareholder return achieved over a given time period relative to the total shareholder return over the same time period for a comparable set of companies.
Continuous service until the performance expiry date

Absolute Total Shareholder Return (‘TSR’)

50% of the Performance Rights will be subject to an absolute total shareholder return hurdle over the Performance Period and will be tested at 31 January ( Test Date ), 3 years after the start date. A TSR equal to a Compounded Annual Growth Rate (CAGR) of at least 15% per annum over the Performance Period is required in order for any of the Performance Rights to vest. The TSR is calculated by comparing the Base Price against the share price on the Test Date plus any dividends paid throughout the Performance Period, which is then computed into an equivalent per annum return.

For the purposes of the Absolute TSR test, the Board have elected to set the Base Price of FAR Shares as at 1 February, which is the 20 day volume weighted average price ( VWAP ) preceding 1 February.

Absolute TSR performance:

Above 25% CAGR, 50% of the performance rights granted will vest.
Between 15% and 25% CAGR, pro-rata 25%-50% of the performance rights granted will vest.
At 15% CAGR, 25% of the performance rights granted will vest.
Less than 15% CAGR, no performance rights will vest.

Relative Total Shareholder Return (‘TSR’)

The remaining 50% of the Performance Rights will be subject to a Relative TSR hurdle over the three year Performance Period to 31 January and will be tested at the end of this period. The TSR performance of FAR Shares will be compared to the TSR performance of all other shares in a comparator group, being the S&P/ASX Energy 300 Index, and Performance Rights will vest only if FAR’s TSR performance is at least at the 50th percentile.

The Performance Rights also contain other provisions including the ability for the Board at its absolute discretion to determine that no relative TSR Performance Rights will vest if the Company’s TSR performance is negative, change of control events and good and bad leaver provisions relating to unvested Performance Rights.

Relative TSR performance:

At or above the 75th percentile, 50% of the performance rights granted will vest.
Between 50th percentile and 75th percentile, pro-rata 25%-50% performances rights granted will vest.
At 50th percentile, 25% performance rights granted will vest.
Below 50th percentile, no performance rights will vest.

23. KEY MANAGEMENT PERSONNEL COMPENSATION Key management personnel compensation

The aggregate compensation of the key management personnel of the Group and the Company is set out below:

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Short-term employee benefits|3,235,535|2,394,291|
|Post-employment benefits|129,846|131,507|
|Share-based payment|275,592|1,715,046|
|Other long-term benefits|124,442|59,074|
|Total|3,765,415|4,299,918|

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24. RELATED PARTY DISCLOSURES

(a) Equity interests in related parties

Equity interests in subsidiaries

Details of the percentage of ordinary shares held in subsidiaries are disclosed in Note 19 to the financial statements.

Equity interests in associates and joint operations Details of interests in joint operations are discussed in Note 18.

25. SUBSEQUENT EVENTS

On the 26th February 2018, FAR announced a farm in deal for blocks A2 and A5 to PETRONAS, the National Oil Company of Malaysia. The farm-in deal with PETRONAS requires PETRONAS

to fund 80% of total well costs through an exploration well, Samo-1, up to a maximum total cost of US$45.0 million. Based on a completion date of 31 March 2018, FAR is to be paid estimated cash of US$13.5 million for reimbursement of back costs and cash consideration. In addition to this, PETRONAS will fund FAR’s share of non-well costs up to a maximum amount of US$1.5 million.

26. REMUNERATION OF AUDITORS

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Auditor of the Parent Entity:|
|Audit or review of the financial report|84,027|70,700|
|-|
|Audit of foreign subsidiaries|19,552|
|Non-audit services|9,776|-|
|113,355|70,700|

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The auditor of the Group is Deloitte Touche Tohmatsu.

27. PARENT ENTITY DISCLOSURES

(a) Financial position

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Assets|
|Current assets|53,904,904|48,845,228|
|Non-current assets|126,485,371|101,669,550|
|Total Assets|180,390,275|150,514,778|
|Liabilities|
|Current liabilities|9,147,261|6,793,675|
|Non-current liabilities|110,378|55,869|
|Total Liabilities|9,257,639|6,849,544|
|Equity|
|Issued Capital|374,521,076|297,933,534|
|Reserves|
|– Option reserve and equity component on convertible notes|8,891,614|8,445,445|
|– Foreign currency translation reserve|(2,948,797)|4,768,226|
|Accumulated losses|(209,331,257)|(167,481,971)|
|Total Equity|171,132,636|143,665,234|

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2017 FAR Annual Report 75

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2017

(b) Financial performance

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||||
|---|---|---|
|Year ended|Year ended|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Loss for the year|(41,849,286)|(22,286,050)|
|Other comprehensive income/loss|(7,717,023)|1,716,094|
|Total comprehensive loss|(49,566,309)|(20,569,956)|

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(c) Guarantees entered into by the parent entity in relation to the debts of its subsidiaries

Other than the Deed of Cross Guarantee disclosed in Note 19, at reporting date the only other guarantees entered into by the Parent Entity in relation to the debts of its subsidiaries are the following:

a parent company guarantee provided to the Kenyan Ministry of Energy for the performance of the third year of the second additional exploration period limited to US$728,450 (2016:US$728,450) and
a parent company guarantee provided to the Gambian Ministry of Energy to guarantee 100% of the work obligations of the Initial Exploration Period of the Blocks A2 and A5 licence Agreement including the drilling of an Exploration Well before 31 December 2018 or such later date if the current licence periods are extended. The maximum amount of the parent company guarantee is US$33,000,000.

(d) Contingent liabilities of the parent entity

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Contingent liabilities|
|Guinea-Bissau – contingent payment from future production|16,658,167|17,965,727|
|Guinea-Bissau – contingent withholding tax liability|727,592|784,704|
|17,385,759|18,750,431|

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Refer to Note 17 for further details.

(e) Commitments for capital expenditure entered into by the parent entity

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||||
|---|---|---|
|31 Dec 2017|31 Dec 2016|
|AU$|AU$|
|Exploration and evaluation assets|
|Not longer than 1 year|3,869,154|30,990,005|
|-|-|
|Longer than 1 year and not longer than 5 years|
|3,869,154|30,990,005|

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Refer to Note 16 for further details.

Pursuant to the Listing requirements of the Australian Securities Exchange

Number of holders of equity securities

Ordinary Shares

At 16 March 2018, the issued capital comprised of 5,461,532,458 ordinary shares held by 11,205 holders.

Unlisted performance rights

At 19 March 2018, there were 29,334,000 unlisted performance rights, with a $nil exercise price and expiry dates of 31 January 2022, held by 10 holders, each with a holding of greater than 100,000 performance rights. Each performance right converts to one share. Performance Rights do not carry the right to vote.

Unlisted Options

At 19 March 2018, there were 60,000,000 unlisted options, with a 10 cent exercise price and 1 June 2018 expiry date, held by 10 holders, each with a holding of greater than 100,000 options. Each option converts to one share. Options do not carry the right to vote.

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Spread details as at 16 March 2018 – Ordinary Shares

Spread details as at 16 March 2018 – Ordinary Shares
Number of Holders	Number of Units % of Total Issued Capital
1 - 1,000 606	243,110 0.00
1,001 - 5,000 502	1,624,597 0.03
5,001 - 10,000 949	7,861,520 0.14
10,001 - 100,000 5,026	224,173,977 4.10
100,001 and over 3,348	5,227,629,254 95.72
Total 10,431	5,461,532,458 100
Holding less than a marketable parcel 1,281

Substantial Shareholder

Substantal Shareholder
Number of shares Percentage
Meridian Asset Management 758,225,755 13.88
Farjoy Pty Ltd 514,463,236 9.42
FIL Limited 276,993,874 5.22
Top Twenty Shareholders as at 16 March 2017 Number of shares Percentage
Citcorp Nominees Pty Limited 870,069,466 15.93
HSBC Custody Nominees (Australia) Limited 805,957,723 14.76
Farjoy Pty Ltd 514,463,236 9.42
J P Morgan Nominees Australia Limited 256,399,803 4.69
Mr Rex Seager Harbour 108,612,253 1.99
Mr Oliver Lennox-King 75,647,869 1.39
BNP Paribas Noms Pty Ltd 72,129,261 1.32
Toad Facilites Pty Ltd 67,528,589 1.24
Natonal Nominees Limited 59,743,684 1.09
HSBC Custody Nominees (Australia) Limited 51,546,945 0.94
Fountain Oaks Pty Ltd 34,200,366 0.63
Rc Capital Investments Pty Ltd 29,183,060 0.53
Floteck Consultants Limited 28,000,000 0.51
Mr Benedict Clube 22,000,000 0.40
N & P Superannuaton Pty Limited 19,298,839 0.35
Almeranka Superannuaton Pty Ltd 18,757,721 0.34
Ms Catherine Norman 18,065,883 0.33
Kalan Seven Pty Ltd 18,000,000 0.33
Mr John Daniel Powell 17,791,645 0.33
BNP Paribas Nominees Pty Ltd 17,012,317 0.31
3,104,408,660 56.84

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2017 FAR Annual Report 77

CORPORATE DIRECTORY

DIRECTORS

Nicholas Limb (Chairman)

Catherine Norman (Managing Director) Benedict Clube (Executive Director)

Timothy Woodall (Non-Executive Director) Reginald Nelson (Non-Executive Director)

COMPANY SECRETARY

Peter Thiessen

REGISTERED OFFICE & PRINCIPAL PLACE OF BUSINESS

Level 17, 530 Collins Street Melbourne Victoria 3000 Australia

Telephone: +61 (0) 3 9618 2550 Facsimile: +61 (0) 3 9620 5200

Website: www.far.com.au Email: [email protected]

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SHARE REGISTRY

BANKERS

Westpac Banking Corporation 360 Collins Street Melbourne Victoria 3000 Australia

Computershare Investor Services Pty Ltd Yarra Falls 452 Johnston Street Abbotsford Victoria 3067

Stanbic Bank Limited Level 5, Stanbic Building Kenyatta Avenue Nairobi Kenya

Telephone: +61 (0) 3 9415 4000 Facsimile : +61 (0) 3 9473 2500 Website: www.computershare.com.au

Standard Chartered Bank Gambia Limited 8 Ecowas Avenue Banjul, The Gambia

STOCK EXCHANGE LISTINGS

Australian Securities Exchange ASX Code: FAR

SOLICITORS

Baker & McKenzie Level 19, 181 William Street Melbourne Victoria 3000 Australia

ADR DEPOSITARY

BNY Mellon 101 Barclay Street New York New York 10286 United States of America

AUDITORS

Deloitte Touche Tohmatsu 550 Bourke Street Melbourne Victoria 3000 Australia

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This document is intended to be distributed electronically. Please consider the environment before you print. Design: Pauline Mosley www.paulinemosley.com

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FAR Ltd Level 17, 530 Collins Street Melbourne Victoria 3000 T: +61 (0) 3 9618 2550 F: +61 (0) 3 9620 5200 W: www.far.com.au

AI assistant

FAR LIMITED — Annual Report 2017

64899_rns_2018-03-19_1c80f331-cbbd-4683-9848-3417066c3179.pdf

CONTENTS

ABOUT US

2017 HIGHLIGHTS

Signed Area of Mutual Interest Agreement with CNOOC UK

March 2017

CHAIRMAN’S REVIEW

Fellow shareholders,

SENEGAL

SENEGAL

SNE-5 WELL RESULT

VR-1 WELL RESULT

SNE-6 WELL RESULT

SENEGAL

FAN SOUTH-1 WELL RESULT

SNE NORTH-1 WELL RESULT

DJIFFERE BLOCK OPTION

The Gambia

GUINEA-BISSAU

SINAPA (BLOCK 2) AND ESPERANÇA (BLOCKS 4A & 5A) 21.42% paying interest, 21.42% beneficial interest Operator: Svenska Petroleum Exploration AB (‘Svenska’)

KENYA

BLOCK L6

Surrounded by proven petroleum systems

WESTERN AUSTRALIA

WA-457-P OFFSHORE DAMPIER BASIN 100% paying and beneficial interest Operator: FAR Ltd

CORPORATE ACTIVITY

EXPLORATION ASSETS

*Disclaimers

*Notes to Prospective Resources Estimates

GOVERNANCE AND SUSTAINABILITY

Corporate Governance

Charters

Policies

Transparency

Environment

Community and social programs

DIRECTORS’ REPORT

INFORMATION ABOUT THE DIRECTORS

Nicholas James Limb – Non-Executive Chairman Bsc (Hons) MAusIMM (appointed 28 November 2011)

Catherine Margaret Norman – Managing Director Bsc (Geophysics) (appointed 28 November 2011)

Benedict James Murray Clube – Executive Director and Chief

Reginald George Nelson – Non-Executive Director

BSc, Hon Life Member Society of Exploration Geophyscists, FAusIMM, FAICD (appointed 9 April 2015)

Timothy Roy Woodall – Non-Executive Director BEc, FCPA, GAICD (appointed 1 August 2017)

Albert Edward Brindal – Non-Executive Director BCom, MBA, FCPA (Retired 29 May 2017)

DIRECTORSHIPS OF OTHER LISTED COMPANIES

DIRECTORS’ SHAREHOLDINGS

REMUNERATION OF KEY MANAGEMENT PERSONNEL

SHARE OPTIONS AND PERFORMANCE RIGHTS GRANTED TO DIRECTORS AND SENIOR MANAGEMENT

PRINCIPAL ACTIVITIES

OPERATING RESULTS

DIVIDENDS

COMPANY SECRETARY

REVIEW OF OPERATIONS

Financial position

Business Strategy and prospects

MATERIAL BUSINESS RISKS

TECHNICAL AND OPERATIONAL RISKS

Exploration

Other operational risks

JOINT OPERATION RISK

GOVERNMENT AND REGULATOR RISK

SOVEREIGN RISK

ENVIRONMENTAL RISKS

CHANGES IN STATE OF AFFAIRS

Senegal

The Gambia

Guinea-Bissau

Kenya L6

Australia

Subsequent events

LIKELY DEVELOPMENTS

INDEMNIFICATION OF OFFICERS AND AUDITORS

DIRECTORS’ MEETINGS

ENVIRONMENTAL REGULATIONS

PROCEEDINGS ON BEHALF OF THE COMPANY

NON-AUDIT SERVICES

1.1 Key Management personnel

FAR LIMITED Annual Report 2017