FAR LIMITED — Annual Report 2016

Mar 21, 2017

Annual Report 2016

FAR’s foundation for success

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CONTENTS

• 02 Chairman’s Review

• 04 Company Highlights

• 06 Operati ons Review

• 20 Corporate Governance Statement

• 21 Community & Social Programs

• 22 Directors’ Report

• 38 Auditor’s Independence Declarati on

• 39 Independent Auditor’s Report

• 43 Directors’ Declarati on

• 44 Consolidated Statement of Profi t or Loss and Other Comprehensive Income

• 45 Consolidated Statement of Financial Positi on

• 46 Consolidated Statement of Changes in Equity

• 47 Consolidated Statement of Cash Flows

• 48 Notes to the Financial Statements

• 75 Supplementary Informati on

• 76 Corporate Directory

2016

WORLD CLASS SNE FIELD PATHWAY TO COMMERCIALITY

2016 FAR Annual Report

1

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CHAIRMAN’S REVIEW

Fellow shareholders,

FAR has had a busy, remarkable and highly successful year. Since the discovery of two very large oil fields offshore Senegal, FAN and SNE, FAR has drilled seven successful wells in the basin to evaluate the size and deliverability of the SNE field. We continue to spin the drill bit in anticipation of finalising the appraisal of SNE and complete the development concept for the field in a few months.

The year started with the drilling of the first appraisal well on the SNE oilfield that FAR and its partners discovered 14 months earlier in November 2014 in the Sangomar Deep Block offshore Senegal. Appraisal drilling continued over the first half of the year with a further three wells drilled and all with remarkable results. The world’s largest oil discovery for 2014 progressively doubled in size over the period of the appraisal drilling and now stands at 641 mmbbls (2C, gross unrisked, with 96 mmbbls net to FAR) and flow testing of both the primary and secondary reservoirs proved that the SNE field would deliver at world class rates.

As I write, we are drilling the second of 3 appraisal wells planned for the 2017 drilling campaign. The appraisal objectives of proving the SNE field size, deliverability and connectivity have been met with the latter being completed by drilling the SNE-6 pulsing well, the last in the 3 well campaign. The SNE field size continues to grow with each appraisal well drilled. Having passed the minimum economic field size for offshore Senegal, FAR made a statement on the commercial viability of developing the SNE field in September. At the time, the Operator released preliminary economics for the field that state that at a US$70/bbl oil price, the field has a value (NPV) of US$12.50/bbl. We think the rout in the oil price gives us scope for even better economics as we move towards construction.

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The world’s largest oil discovery for 2014 progressively doubled in size over the period of the appraisal drilling...

With each drilling campaign, the costs of drill rigs has been coming down. In a little over two years since the discovery of SNE, deep water rig rates have dropped from US$675,000/day to below $200,000/day and our joint venture has been able to take advantage of this in contracting for our current rig which is not only lower cost but has marked better performance as evidenced by the SNE-5 well which, as announced in March, was completed 21 days ahead of schedule.

The nature of such intense project evaluation comes with the need for significant funding and we must be appropriately funded or risk losing value. Thanks to the ongoing support of our shareholders, FAR finished the 2016 year with an adequate cash position of $47M which will fund us through the budgeted costs of the currently approved drilling program in 2017. This important funding task is very time consuming and our senior executive staff have worked very hard during the year making sure our value proposition is well understood by the market.

The implementation of our social media campaign in late 2015 has seen good support for our You Tube and Twitter releases in addition to the regulatory information released on our website. We continue to innovate to bring news and information to our wide shareholder base.

FAR has had a strong relationship with the country of Senegal for 11 years and 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 the joint venture.

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2

...most excitingly we are likely to drill at least one exploration target in the current campaign and we look forward to demonstrating that the FAN and SNE discoveries are only the beginning.

positioned ourselves comprehensively from a strategic standpoint and retain the option to initiate international arbitration. This has placed a very heavy additional work load on our executive and I am very proud of what they have achieved. It is worth remembering that none of this affects our current rights or position and is a matter of managing an opportunity that affords plenty of upside.

Our primary school renovation was particularly successful and will be hopefully grounding the next generation of engineers, accountants and environmentalists that will support the growth of the oil industry in Senegal in the future.

FAR’s corporate strategy changed in the wake of the discoveries offshore Senegal and the corporate focus for new ventures was shifted to the MSGB basin and the shelf edge: the geological setting for the SNE field where FAR has considerable technical expertise. FAR looks forward to capitalising on the knowledge gained from our exploration efforts offshore Senegal and adding to the portfolio of assets with additional high quality acreage.

As a result of the downturn, we continue to tightly manage our costs and although we have had an extraordinarily successful year with the drill bit, the company elected to not award any STI’s to staff. The FAR team continues to deliver on our strategic plan and remains focused and determined.

The market in the year continued to be tough for oil companies. The sustained low oil price has left the industry today considerably leaner as a result and we have seen that the major companies have not been immune to the very difficult commodity market conditions. Our partner in the Senegal joint venture, ConocoPhillips, agreed to sell their 35% share at a price of approximately US$2.20/bbl of 2C resource at that time to Woodside Energy, a price that was surprisingly low and represented an attractive opportunity. The sale triggered the rights of partners to pre-empt and ConocoPhillips issued the pre-emption notice but on our expression of interest chose to refuse access to all of the required information. The fact that FAR has not been afforded these same terms and conditions as the purchaser has resulted in a dispute with Conoco Phillips pursuant to the joint venture agreement that at the time of writing, has not been resolved. This is a substantial matter financially which involves multiple parties including the Government of Senegal. We have received much shareholder enquiry about progress however as you would appreciate it is difficult for us to comment but suffice to say we have

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.

We look forward to 2017 which we know will be another very busy year for the FAR team. We anticipate that the SNE field will continue to grow in size as we complete the appraisal drilling program and head towards finalising development plans for the field.

Perhaps most excitingly, we are likely to drill at least one exploration target in the current campaign and we look forward to demonstrating that the FAN and SNE discoveries are only the beginning.

Nic Limb Chairman

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2016 FAR Annual Report 3

AN OUTSTANDING YEAR OF SUCCESS

End of year cash position A$47M with no debt

2016 capital raising A$60M

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Drilled 4 appraisal wells proved SNE is a world-class field

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6 6
/
successes
to date in frontier basin
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SNE oil field
minimum
economic field
size surpassed
1 September
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Drilling costs are coming down

2014 US $675K / day 2015/16 US $330K / day 2017 US $190K / day

4

SNE-2

SNE-3

BEL-1

SNE-4

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FAR awarded breakthrough company of the year Africa Assembly London 21 June

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high impact
social programs
2
in Senegal
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2016 FAR Annual Report 5

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’)

FAR has continued to build on the basin opening Senegal oil discoveries made in 2014 by the FAN-1 and SNE-1 wells.

The SNE discovery was ranked as the world’s largest oil discovery for 2014 with potential resource volume to justify a stand-alone oil development project. The SNE discovery was the focus of the first phase of the joint venture’s appraisal drilling program. The key aims of that program were to prove the Minimum Economic Field Size (MEFS) for the SNE discovery, which FAR estimated to be approximately 200 million barrels (mmbbls) of recoverable oil, and determine flow rates and connectivity of the reservoirs across the field in order to optimise a future development.

In October 2015, the Senegal joint venture contracted the Ocean Rig Athena, a seventh-generation state of the art deep water drill ship, for its first phase 2015/16 Senegal drilling and evaluation program. The Athena rig was contracted at a substantially reduced day rate, due to prevailing low oil price market conditions. This combined favourably with efficient drilling operations to deliver significantly reduced drilling costs in comparison to what was previously experienced by the joint venture in 2014 and under a higher oil price environment.

Over 2016, FAR successfully completed the first phase of its Senegal SNE oil field appraisal program with the drilling and evaluation of the SNE-2, SNE-3, BEL-1 and SNE-4 wells. Each of these wells confirmed approximately 100m gross oil column, high quality 32⁰ API oil and the presence and correlation of principal reservoir units over a distance of approximately 9km in a north-south direction (BEL-1 to SNE-3) and 5km east (SNE-4), respectively across the SNE oil field. In addition, oil flow tests

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Senegal
Rufisque
Sangomar
FAN-1
BEL-1
Sangomar
Deep SNE-2
SNE-1
Djiffere Offshore
SNE-3
0 50
km SNE-5 SNE-4
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FIGURE 1: Senegal location map showing the FAN and SNE well locations

conducted at SNE-2 and SNE-3 confirmed the SNE field can deliver commercially viable well production rates. Each of these appraisal wells were drilled safely, ahead of schedule, and under budget. The joint venture took advantage of the lower rig rate and expanded the originally planned three well appraisal program to include a fourth well. The location of the four appraisal wells are shown in Figure 1.

The ‘world class’ size of the SNE oil field was reaffirmed in 2016 with FAR completing three consecutive, independently audited, increases to its recoverable oil resource estimates. These independently audited assessments increased FAR’s SNE field 2C contingent resources from 330 mmbbls post the SNE-1 discovery to 641 mmbbls on a gross, unrisked basis.

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SENEGAL
Oil
Gas BEL-1 SNE-2 SNE-1 SNE-3 SNE-4
Senegal
2015 GOC OWC
3D Seismic
FAR Djiffere
3D Seismic
0 5
SNE field km
0 25
km 3D Seismic
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FIGURE 2: FAR’s Senegal licences showing the SNE field location and 3D seismic coverage

The first of FAR’s SNE contingent resource assessments was completed on 8 February 2016 and prior to the appraisal drilling campaign with the Ocean Rig Athena drillship and incorporated data available from SNE-1, FAN-1 and reprocessed 3D seismic. FAR’s second contingent resource assessment was completed on 13 April 2016 following the drilling and evaluation of the SNE-2 and SNE-3 well results. The third and final assessment on 23 August 2016 incorporated the results and evaluation of BEL-1 and SNE-4 wells. The reported increases in FAR’s SNE field contingent resource estimates during 2016 highlights the success of the 2016 appraisal drilling campaign and the overall level of confidence of the size of the field. Figure 4 illustrates the growth in the SNE oil field over the appraisal drilling period.

As a result of this growth in contingent resources, FAR announced in September 2016 that the SNE field had surpassed the MEFS threshold of 200 mmbbls. This was achieved only 21 months after the initial SNE-1 discovery well was drilled and this success is largely attributable to the highly efficient drilling and evaluation program and positive results from each of the appraisal wells.

SNE development planning is now underway after the encouraging results from the SNE appraisal drilling and ongoing evaluation activities which provided the required support to move the SNE project into the pre-FEED stage (Front End Engineering and Design). Studies are currently focussed on optimising and scaling the field development which is expected to form an anchor project with scope for expansion and tie-backs.

FIGURE 3: Well locations in the SNE field

SNE-2 WELL RESULT

On 4 January 2016, FAR announced the results of the successful SNE-2 flow test:

• A drill stem test (DST) of the lower principal oil reservoir unit over a 12m interval (~11.5m net) flowed oil at a maximum stabilised constrained rate of ~8,000 bopd on a 48/64” choke. The interpreted unconstrained flow rate of this interval was greater than the testing equipment capacity of 10,000 bopd. This result confirmed the high deliverability of the principal SNE reservoir units.

• A DST of a shallower thin bed reservoir unit over a 15m interval (~3.5m net) flowed oil at a maximum rate of ~1,000 bopd on a 24/64” choke. The flow from this interval was unstable due to the 4.5” DST tubing, however, this result confirms the potential of the upper reservoir units to produce at commercially viable rates and make a material contribution to SNE oil resource and production volumes.

• Gross oil column thickness of 103m and the same 32° API oil quality as seen in SNE-1.

• A total of 216m of continuous core (100% recovery) was recovered across the entire SNE field reservoir interval.

• SNE-2 confirmed the correlation of the principal reservoir units between SNE-1 and SNE-2 and the potential for lateral reservoir continuity.

8

OPERATIONS REVIEW

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SNE-3 WELL RESULT

SNE-3 was the second SNE oil field appraisal well to be drilled in the phase one appraisal program. After completion of SNE-2, the Ocean Rig Athena returned to the SNE-3 location and began deepening the well on 18 January 2016. SNE-3 is located in the Sangomar Deep Offshore Block, approximately 3km south of the initial SNE-1 discovery well.

On 9 March 2016, FAR announced that SNE-3 was successfully tested and operations safely completed following drilling, coring, logging and drill-stem testing (DST). Flow rates recorded were equipment constrained and exceeded FAR pre-drill expectations with results as follows:

• Two drill stem tests (DST) were conducted within the upper reservoirs, confirming the deliverability of these units. The first DST, from a 15m zone, flowed at a maximum rate of 5,400 barrels of oil per day (bopd) and delivered a stabilised flow of 4,000 bopd over a 24 hour period. For the second DST, an additional zone of 5.5m was opened up and combined with the 15m zone to deliver a stabilised flow rate of 4,500 bopd over a six hour period. Both flow tests used a 56/64” choke.

• Confirmation of excellent reservoir quality and good correlation of the principal reservoir units between SNE-1, SNE-2 and SNE-3.

• 144m of continuous core was taken across the entire reservoir interval with 100% recovery.

• Gross oil column thickness at SNE-3 confirmed at 101m gross, showing a similar column as seen at SNE-2 of 103m gross and at SNE-1 of 96m gross.

• The same 32° API oil quality as seen in SNE-1 and SNE-2.

• Reservoir units were intersected shallower to prognosis (higher than expected on the structure) suggesting the southern flank of the oil field is more extensive.

• Gauges were set in the SNE-3 well so that it may be used for interference testing in the future.

BEL-1 WELL RESULT

On 11 April 2016, FAR announced that BEL-1 was successfully drilled and operations safely completed following drilling, coring, and logging operations.

BEL-1 had dual objectives to evaluate the Buried Hills exploration play overlying the SNE field in this location, as well as appraise the deeper northern flank of the SNE oil field.

The BEL-1 Buried Hills section confirmed two gas bearing sandstone reservoirs in lower zones with upper zones interpreted to be tight. No water-bearing units were encountered in this section, supporting potential for down-dip oil with extensive structural closure.

The deeper BEL-1 SNE oil field appraisal well extended the reservoirs and confirmed both the oil column (approximately 100m gross) and 32° API oil quality over the northern flank of the SNE field. It also produced other significant results including;

• Confirmed good quality reservoir sands within the reservoir units.

• Good correlation and presence of the principal reservoir units between the SNE-1, SNE-2, SNE-3 and BEL-1 wells over a distance of more than 9km.

• Multiple samples of gas, oil and water recovered to surface.

• Similar oil quality as seen in SNE-1, SNE-2 and SNE-3.

• 144m of continuous core taken across the entire oil reservoir interval with 100% recovery.

Operational efficiencies from successfully drilling the SNE-2, SNE-3 and BEL-1 wells meant the joint venture was ahead of schedule and under budget and in a position to drill a fourth evaluation well at essentially the same total initial budget cost. The SNE-4 well was therefore selected as an option well to appraise the eastern extent of the SNE field, located approximately 5km south-east of SNE-1.

Flow test results from both SNE-2 and SNE-3 have demonstrated that multiple reservoirs within the SNE field are capable of flowing at commercially viable flow rates.

2016 FAR Annual Report

9

SENEGAL

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Pre-Drill Post discovery Post SNE-2 and SNE-3 Post BEL-1 and SNE-4
(Oct 2014) (Nov 2014) (April 2016) (August 2016)
BEL-1
SNE-1
SNE-1 discovery SNE-1 SNE-1
0 5 0 5 0 5 0 5
km km km km
SNE-2 SNE-2
SNE-3 SNE-3 SNE-4
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FIGURE 4: Field size growth

SNE-4 WELL RESULT

On 19 May 2016, FAR announced that SNE-4 was successfully drilled and operations safely completed following drilling, coring, and logging operations.

The SNE-4 appraisal well results further confirmed the scale and extent of the SNE field resource. Key results included:

• The extension of reservoirs in the eastern portion of the SNE field located 5km east and down dip from the SNE-3 well location (refer Figure 4).

• Presence and correlation of principal reservoir units between each of the wells across the field.

• Oil bearing upper reservoir sands of similar quality to those encountered as gas bearing elsewhere in the field.

• Shallower gas sands first discovered in BEL-1 and SNE-3 were also present and gas bearing in SNE-4. The potential for down dip oil in these extensive reservoirs is being assessed.

• Gross oil column of 102m.

• Multiple samples of gas, oil and water recovered to surface. SNE-4 has also confirmed the same 32° API oil quality as seen in other wells across the SNE oil field.

• 108m of continuous core was taken across the oil bearing reservoir interval with 100% recovery.

After completion of SNE-4 operations, the Operator released the Ocean Rig Athena drill ship.

SNE OIL FIELD CONTINGENT RESOURCES UPGRADES

On 13 April 2016, FAR announced that RISC Operations Pty Ltd (‘RISC’) provided FAR with an updated Independent Resources Report for FAR’s SNE oil field offshore Senegal, following the drilling of two successful appraisal wells, SNE-2 and SNE-3.

The SNE contingent resources set out in RISC’s April Independent Resource Report represented a material increase to the estimates previously reported by FAR and audited by RISC in February 2016 (Refer: FAR 2015 Annual Report) . The key elements of the RISC report included:

• SNE oil field contingent resources (100% basis, unrisked, recoverable) upgraded by RISC to 277 mmbbls 1C, 561 mmbbls 2C, 1071 mmbbls 3C.

• The SNE oil field contingent 2C resource of 561 mmbbls (84 mmbbls net to FAR) represented a 20% increase to the previous 2C estimate of 468 mmbbls (70 mmbbls net to FAR).

On 23 August 2016, FAR announced that RISC provided FAR with a further updated Independent Resources Report for the SNE oil field, following the drilling of two further successful appraisal wells, BEL-1 and SNE-4.

The SNE contingent resources set out in RISC’s August Independent Resource Report represented a further significant increase to the estimates previously reported by FAR in April 2016 (Refer: FAR ASX announcement 13 April 2016) and included:

• SNE oil field contingent resources (100% basis, unrisked, recoverable) upgraded to 348 mmbbls 1C, 641 mmbbls 2C, 1,128 mmbbls 3C.

• The SNE oil field contingent 2C resource of 641 mmbbls (96 mmbbls net to FAR) represented a 14% increase to the previous 2C estimate of 561 mmbbls (84 mmbbls net to FAR).

RISC’s reports were based on reviews of a modified probabilistic resource evaluation carried out by FAR in accordance with industry standard SPE-PRMS definitions.

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SNE OIL FIELD COMMERCIAL VIABILITY CONFIRMED

On 1 September 2016, FAR announced that it had determined the Minimum Economic Field Size (MEFS) for a commercial development at SNE had been achieved in only 21 months from the initial SNE-1 discovery well. The MEFS for the SNE project was estimated to be approximately 200 mmbbls.

FAR completed pre-engineering studies with engineering consultancy AMOG and prepared an SNE field concept development plan based on its 2C Contingent Resource estimate of 641 mmbbls. This envisages a standalone FPSO development as an anchor project with topside expansion capability for later SNE field development phases and satellite tie-backs. FAR’s development concept represents a phased development approach with a plateau production rate of 140,000 bopd and first oil in 2022.

FAR’s cost estimates are as follows:

• Development expenditure: US$13-15/bbl

• Operating expenditure: US$12-14/bbl (including FPSO lease costs)

• Development cost split: Drilling and completions 45%; Subsea 46%; Project + Other 9%

Drilling and subsea costs have decreased significantly over the last three years. Opportunities to further reduce well and subsea costs through design optimisation and standardisation are being investigated. The current market also offers potential, costeffective FPSO conversion opportunities that could also enable accelerated production.

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Stena DrillMAX deep
water drill ship
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The Operator has reported economic scenarios for a standalone SNE development project under different oil price assumptions (see Figure 5) that highlight SNE is a robust project. Breakeven oil price was estimated at US$35/bbl and based on a US$70/ barrel oil price; NPV (net present value) at FID (Final Investment Decision) was US$12.50 per barrel and internal rate of return (IRR) at FID of 38%. The Operator’s valuations are consistent with FAR’s estimates.

FIGURE 5: Operator Economic Development Scenario

2017 SENEGAL DRILL PROGRAM

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20 50%
10% return breakeven at
18 45% FID oil price: <US$35/bbl
16
40%
14 US
$12.50/bbl
35%
12
10 30%
8
25%
6
20%
4
15%
2
0 10%
@ $90/bbl @ $70/bbl @ $50/bbl @ $90/bbl @ $70/bbl @ $50/bbl
(LEFT CHART) NPV per barrel of the (RIGHT CHART) IRR in percent from
SNE oil field at FID under different the SNE oil field at FID under different
price assumptions. oil price assumptions.
Cairn IRR at FID, %
Cairn NPV/bbl at FID, $/bbl
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Source: Cairn Energy estimates (refer Cairn Energy Half Yearly Result 16/08/2016) based on Cairn 2C 473 mmbbls.

The Senegal joint venture reached agreement in the December 2016 quarter to drill two further appraisal wells into the SNE oil field. The first well, SNE-5, began drilling on 21 January 2017 and was drilled and flow tested to evaluate the upper series sands. Pressure gauges have been installed for future use in an interference test pattern to test the connectivity of the upper sands. The location of the SNE-5 well is shown in Figures 4 and 6. The results from the SNE-5 well and the interference test will be used to better understand the production characteristics of the upper reservoirs and will be important in optimising a development plan and capital expenditure for the SNE field development.

An extensive rig tender evaluation process was undertaken by the JV at the end of 2016 and as a result, the Stena DrillMAX drillship (see above) was contracted for a two well firm drilling program, plus multiple option wells. The Stena DrillMAX is a sixth generation, dynamically positioned, deep water drill ship with a rig crew that has extensive international and regional West African experience.

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SENEGAL

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Oil
Gas
BEL-1
SNE-2
SNE-1
SNE-3 SNE-4
SNE-5
0 5
km
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FIGURE 6. Well location map

EXPLORATION POTENTIAL

FAR’s exploration strategy remains focussed on its core asset base and to mature its offshore Senegal prospect inventory with an initial focus on proven play types located along trend on the shelf edge and in basinal areas.

FAR has approximately 7,500 square kms of area under its production sharing licence in Senegal.

Success with the FAN-1 and SNE-1 basin opening oil disco ~~veries~~ and subsequent successful appraisal of the SNE oil field, ~~has~~ proved the area has a prolific working source rock, excell ~~ent~~ reservoir development and a good working seal. The new ~~3D~~ seismic data has allowed FAR to gain further confidence i ~~n~~ mapping traps along the extension of the SNE trend and ~~also~~ new plays and prospects in the acreage.

On 7 February 2017, FAR announced it updated its RSSD offshore exploration prospect mapping based on the integration of the new 2,400 km² 3D seismic acquired over the RSSD blocks in late 2015 with the previous 3D seismic and well data.

FAR has identified 1,563 mmbbls, or 234 mmbbls net to FAR, of undrilled oil prospectivity (P50 basis, unrisked, prospective resource, recoverable) in its offshore Senegal acreage. In addition to the undrilled prospects, the 2C resource in the SNE discovery is 641 mmbbls with 96 mmbbls net to FAR (contingent, recoverable, unrisked). Several Senegal prospects identified by FAR are located within a tieback range of approximately 30kms to an SNE production hub, which means they could have a significant positive impact on the size, scope and future returns generated from the SNE project development (refer Figure 8).

An updated Independent Resources Report for FAR on the exploration potential of FAR’s RSSD offshore blocks has been completed by RISC. The prospective resource estimates detailed in Table 1 are set out in RISC’s report and assess the probabilistic resource evaluation carried out by FAR in accordance with industry standard SPE-PRMS definitions.

FIGURE 7. Cross section showing SNE-5

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WEST SNE-2 SNE-1 SNE-3 SNE-5 SNE-4 EAST
Shales
Maastrichtian Shales
Sandstones
Carbonates
Gas-oil
contact
Upper
sands
Oil-water
contact
TD 2800m TD 2807m
TD 2852m Lower
sands
TD 29 70m
TD 3085m
Depth in mTVDSS Top Aptian Carbonates
Unconformity
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Oil discovery Dakar
Gas discovery Senegal
Late Cretaceous Fan
Late Cretaceous Shelf
Late Albian Shelf
Albian Fan Rufisque
Albian Shelf
Aptian Shelf
Sangomar 3D seismic
RSSD 3D seismic
Rufisque
Onlap
Rufisque Dome wells
Spica
Sangomar
Deep FAN-1 Djiffere
BEL-1
Central Fan
SNE-1 SNE-2 Leebeer Tie back radius
SNE-3
South Fan 0 20
km
Sirius
Summ
Alhamdulillah
Leraw Jabbah
SNE-4
SNE-5
50 m
1000 m ProspectiveShelf Trend
100 m
Sangomar
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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 Rufisque, Sangomar and Sangomar Deep (RSSD) Blocks that contain the significant SNE-1 and FAN-1 oil discoveries (see Figure 2 location map FAR Djiffere 3D seismic).

Under the agreements with Trace, FAR was granted an option to earn a 75% working interest in the Djiffere Block by drilling an exploration well (subject to Government approvals). FAR’s initial 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. Fast track processed seismic data was received during the December quarter and FAR expects to be ready to make a final decision in relation to the option once final processed data has been interpreted.

Table 1:Senegal prospective resources

FIGURE 8: Undrilled exploration prospects defined by 3D seismic data

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Prospective, gross, unrisked Probability
Prospect recoverable oil resources * of success
name Play Best estimate (P50) (mmbbls) (%)
Sirius Albian shelf edge 294 60%
Spica Albian shelf edge 199 37%
Leebeer SNE Late Albian shelf 116 33%
Leebeer Sirius Late Albian shelf 50 20%
Leebeer Spica Late Albian shelf 47 20%
Rufisque Onlap Albian 181 14%
Alhamdulillah Albian Fan 80 23%
Leraw Cenomanian 108 23%
Jabbah Cenomanian 44 25%
Jabbah Deep Cenomanian 111 16%
South Fan Cretaceous Fan 134 18%
Central Fan Cretaceous Fan 96 17%
Total all prospects 1,460
Suum Lead [(1)] Aptian Carbonate Shelf 103
Total prospects & leads 1,563
Total net to FAR 234
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1.5 billion barrels of undrilled prospectivity

(i) Not audited by RSIC

GUINEA-BISSAU

SINAPA (BLOCK 2) AND ESPERANÇA (BLOCKS 4A & 5A) 21.43% paying interest, 15% beneficial interest Operator: Svenska Petroleum Exploration AB (‘Svenska’)

The underlying exploration potential of offshore Guinea-Bissau has long been recognised given the functioning hydrocarbon system, good potential reservoirs and multiple drillable prospects in a wide shallow water shelf setting.

The joint venture acquired additional 3D seismic data to evaluate the western shelf edge margin of the large Atum prospect that was previously only partially covered by 3D seismic. Atum is potentially analogous to the SNE oil discovery. The seismic data has been acquired, processed and interpreted and the joint venture is considering options for a future work program. Discussions are progressing with the regulator in relation to amendments to the current licence including an extension to the current period by the end of 2019.

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0 50 Senegal
km
Guinea-Bissau
1
2
3
4A
4B 5A
6A
5B
7A
6B
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FIGURE 9: Location of FAR’s blocks offshore Guinea-Bissau

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TABLE 2: Guinea-Bissau project contingent and prospective resources []
Salt dome
1
Contingent & Prospective Resources [] Prospect/lead3D Seismic Survey 2012
3D Seismic Survey 2014
Low Best High
Guinea-Bissau Estimate Estimate Estimate
Prospect (mmbbls) (mmbbls) (mmbbls)
2
Sinapa Discovery 4.4 13.4 38.9
Total 4.4 13.4 38.9
West Sinapa
Atum Sabayon
Total Net to FAR 0.7 2 5.8 East Sinapa
East Sinapa 1.8 7.5 34.2 Arinca North Solha
West Sinapa 17.7 34.7 251.7 4A
Atum 144 471.7 1,569.6
North Solha 6 28.4 131.6
4B
Arinca 10 59.2 393
5A
Sabayon 3.4 18.1 88.2
Other leads 85.4 303.7 1,032
Total all prospects 269 954 3,500 6A
5B
Total net to FAR 40 143 525 0 20
6B km
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FIGURE 10: Block 2 & Blocks 4A/5A prospects, offshore Guinea-Bissau

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EAST AFRICA

Footprint in proven East African Miocene Reef Play

FAR has an interest in Kenya permit: Block L6. This is located in the heart of the Lamu Basin offshore and onshore Kenya, north of recent world-scale, natural gas discoveries totalling over 100 trillion cubic feet, off the coasts of Mozambique and Tanzania and the Sunbird-1 oil discovery, offshore Kenya.

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KENYA

BLOCK L6

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

The Block L6 permit area, over, 3,134km², has both onshore and offshore potential with water depths varying from shallow transition zones to approximately 400m.

FAR continued discussions over 2016 with the Government of Kenya to secure suitable arrangements pursuant to the Petroleum Sharing Contract to allow exploration activity that has been hindered by past security incidents and land access issues, to commence. In the event these issues are resolved by the Government, FAR is planning to proceed with a 2D onshore seismic survey.

Under the terms of the Joint Operating Agreement, FAR’s partner in the L6 joint venture (Pancontinental Oil and Gas) has been issued with default notices for non-payment of two cash calls in February 2015 and remains in default.

Combined prospective resources for the L6 Block have been assessed at 3.7 billion barrels of oil or 10.2 trillion cubic feet of gas (unrisked, best estimate, 100% basis).

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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 11: A map showing the location of FAR’s L6 Block offshore Kenya

2016 FAR Annual Report 15

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KENYA
Miocene Reefs
Miocene Fans
Eocene Clastics
Cretaceous Clastics
Other leads
& prospects
Gas discovery
Oil & Gas discovery L6
Eocene Oil Kitchen
Kenya
Mbawa
Discovery
Sunbird
Discovery
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FIGURE 12: Leads and prospects mapped offshore Kenya

Combined prospective resources for the L6 Block have been assessed at 3.7 billion barrels of oil or 10.2 trillion cubic feet of gas

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TABLE 3: Estimate of Prospective Resources [] for Block L6, Kenya Prospective
Resources []
Kenya L6 Best Estimate
Prospects Play (mmbbls)
O FFSHORE
Kifaru Miocene Reef Play 178
Kifaru West Miocene Reef Play 130
Tembo Eocene Clastics Play 327
Kiboko Eocene Clastics Play 110
Nyati Eocene Clastics Play 149
Nyati West Eocene Clastics Play 304
Chui Eocene Clastics Play 188
Chui West Eocene Clastics Play 77
Other Eocene Clastics Play 769
Other Miocene Reef Play 1,249
Late Cretaceous Clastics Play 95
To ta l offshore prospects 3,577
Total net to FAR
– offshore prospects 2,146
ONSHORE
Mamba Eocene Clastics Play 31
Kudu Eocene Clastics Play 115
Other Late Cretaceous
Clastics 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
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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 a multi-client 3D seismic survey that acquired data over 62% of the WA-458-P permit. The survey commenced in the second quarter of 2015. FAR received final processed 3D seismic data in February 2017. FAR is planning on acquiring additional 3D seismic data over the remainder of the WA-458-P Block.

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

Australia Prospects	Prospectve Resources*
	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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Mutineer/PitcairnFletcher
Oil field Exeter Finucane
Gas field
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 13: Location of Blocks WA-457-P and WA-458-P, offshore Western Australia

Following the success of FAR’s Senegal program, FAR intends to farm-down its high interest in WA-458-P to focus on delivering shareholder value in the Senegal region.

FAR has submitted a relinquishment request to the regulator of WA-457-P and intends to leave the permit in good standing.

CORPORATE ACTIVITY

At the end of the financial year FAR had a robust cash position with combined cash and long term deposits of AU$46.98 million and no debt. In April 2016, FAR successfully raised approximately AU$60 million (before costs) through a placement of fully paid ordinary shares to institutional and sophisticated investors. The placement was significantly oversubscribed with strong support by existing shareholders, and it also saw the introduction of new institutional investors. Proceeds from the placement are to be used to fund FAR’s continued participation in the drilling and evaluation program offshore Senegal.

FAR holds the majority of its cash in US$’s – the currency in which the substantial majority of costs are incurred.

OIL AND GAS ASSETS

FAR holds a wide portfolio of exploration licences across 9 blocks and permits in Africa and Australia. The core focus area for the company is Africa, and specifically Senegal after making the basin opening FAN-1 and SNE-1 oil discoveries in 2014. FAR completed a four well drilling program offshore Senegal in mid-2016 that focused on appraising the world class SNE discovery with the SNE-2, SNE-3, SNE-4 wells and evaluated the Buried Hills prospect and the northern extent of the SNE field with the BEL-1 well. FAR holds a 0.09375% overriding royalty on T/18P exploration permit (including replacement tenures) located offshore Tasmania in the Bass Basin.

As at the end of 2016, the Company assets are tabled below.

Project	Asset FAR Paying Interest Benefcial Interest Operator Rufsque, Sangomar and Sangomar Deep 16.7% 15.0% Cairn Energy Block 2, 4A, 5A 21.43% 15.0% Svenska Block L6 (ofshore) 60% 60% FAR Block L6 (onshore) 24%(i) 24% FAR WA-458-P 100% 100% FAR WA-457-P 100% 100% FAR (i) Subject to the completon of the farm-out agreement with Milio. Current paying and benefcial interest is 60%.
Senegal
Guinea-Bissau
Kenya
Australia

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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 and 23/08/2016 (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 resource estimates provided in this report are Best Estimates and represent that there is a 50% 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.

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

1. The estimated quantities of Prospective Resources stated above 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.

2. The recoverable hydrocarbon volume estimates prepared by the company and stated in the tables above 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.

3. The Prospective resource estimates have been estimated using deterministic methods using best estimates of all parameters.

4. 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.

5. The Best Estimates reported represent that there is a 50% probability that the actual resource volume will be in excess of the amounts reported.

6. The estimates for unrisked Prospective Resources have not been adjusted for both an associated chance of discovery and a chance of development.

7. The chance of development is the chance that once discovered, an accumulation will be commercially developed.

8. 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.

9. In the table, the abbreviation ‘mmbbls’ means millions of barrels of oil or condensate and ‘bcf’ means billions of cubic feet of gas.

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CORPORATE GOVERNANCE

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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.

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

FAR’s policies and charters can be found on our website and are listed below:

Charters

Board Audit Committee Nomination Committee Remuneration Committee Risk Committee

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Policies

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

FAR’s Corporate Governance Statement can be viewed on the website at: www.far.com.au/governance-social-responsibility/.

FAR has initiated registration to the Extractive Industries Transparency Initiative.

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20

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COMMUNITY & SOCIAL PROGRAMS

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

FAR invests in the following social programs through our Senegal joint venture:

Education and training

Supporting educational institutions

developing petroleum industry and other relevant skills for the potential local future work force. Such training includes English language and presentational skills.

FAR is dedicated to enacting policies and practices that are ethically, socially and environmentally sound and are consistent with FAR’s objective of being a respected community citizen in the stakeholder groups where we conduct FAR’s business.

Community development

Enterprise development

Promoting entrepreneurship as a key capability in helping foster economic growth.

Working with The Hunger Project (THP) supporting a program to create a women-led microfinance program, 10 centres in Senegal serving ~ people in 178,000 villages

FAR is dedicated to supporting activities that deliver positive, lasting social and economic benefits to the people in the communities in which we operate.

people in villages

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FAR directly supported the following activities in Senegal in 2016:

Renovated a primary school in the regional city of Thiess

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Sponsored regional soccer competitions through provision of 200 balls and uniforms

2016 FAR Annual Report 21

DIRECTORS’ REPORT

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The directors of FAR Ltd submit herewith the Annual Financial Report for the year ended 31 December 2016. In order to comply with the provisions of the Corporations Act 2001, the Directors’ Report as follows:

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. Additionally, 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 also a member of the nomination, 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.

Albert Edward Brindal – Non-Executive Director BCom, MBA, FCPA

(appointed 19 December 2007)

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 is also a member of the nomination, remuneration and audit committees.

Reginald Nelson – Non-Executive Director BSc, Hon Life Member Society of Exploration Geophysicists, 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 and 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:

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

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:

	Shares Optons 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 -
A E Brindal	350,955 - -

22

REMUNERATION OF KEY MANAGEMENT PERSONNEL

Information about the remuneration of key management personnel 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 14,319,000 Performance Rights were granted to two executive directors and the three officers of the company as part of their remuneration. 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 2016 after income tax was $21,759,974 (2015: $19,620,114).

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.

DIVIDENDS

The directors recommend that no dividend be paid for the year ended 31 December 2016 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

	FY16 $ FY15 $ Change %
Proft & loss
Revenue	165,777 287,088 (42%)
Expenses	(21,925,751) (19,907,202) 10%
Loss for the period	(21,759,974) (19,620,114) 11%
Basic EPS (cents)	(0.52) (0.57) (9%)
Financial positon
Net assets	144,800,225 102,288,270 42%
Cash balance	46,978,179 60,670,897 (23%)
Cash fows
Operatng cash fow	(20,773,529) (19,118,786) 9%
Investng cash fow	(53,709,928) (31,958,434) 68%
Financing cash fow	60,127,254 42,036,017 43%

The group reported loss for the 2016 year of $21,759,974 is 11% greater than the prior year loss of $19,620,114. Included in the loss are exploration expenses of $16,352,405, which are marginally lower than the prior year of $16,674,745. The Senegal projects represent the vast majority of these costs amounting to $13,452,226 compared with $12,611,392 in the comparative year. Other exploration costs include Australia, Guinea-Bissau and Kenya amounting to $2,384,198 which were down $654,398 year on year. The higher costs in the prior year reflected seismic acquisition programs. The increased loss is due mainly to the higher employee benefits expense of $4,612,423 reflecting higher non cash share based payments of $2,490,223 compared with $1,110,667 in the prior year and the lower foreign exchange gain for the year of $767,004 compared with $1,333,165 in the 2015 year.

Financial position

The Group’s balance sheet was strengthened during the year by a capital raising of $60,000,000 before costs received in two tranches at a share price of 8.5 cents per share. The first tranche unconditional proceeds were received in April and the balance in June subsequent to shareholder approval. Additionally, proceeds of $2,728,000 before costs were received from the exercise of 62 million options at 4.4 cents per share.

Net assets increased during the year by 42% to $144,800,225 (2015: $102,288,270). This is due predominantly to the increase in exploration and evaluation assets of $42,845,520 to $101,706,766 resulting from the capitalisation of the SNE-2, SNE-3, BEL-1 and SNE-4 well costs and the planning and

2016 FAR Annual Report 23

preparation costs incurred for the SNE-5 and SNE-6 wells which commenced drilling in January 2017. Trade and other payables decreased from $12,802,698 to $5,958,709 during the year reflecting lower incurred well costs at 31 December 2016 than the prior year due to the delay in the commencement of the drilling of SNE-5 and SNE-6, whereas in the prior year significant costs had been incurred but not paid on the wells SNE-2, SNE-3 and BEL-1 at 31 December 2015.

Cash was 23% lower than the prior year at $46,978,179 due mainly to higher investing cash outflows amounting to $53,709,928 compared with the prior year of $31,958,434. The additional outflows relate to payments for the drilling of the 4 Senegal wells during the year. Operating cash outflows were $1,654,743 higher reflecting higher exploration and evaluation expense payments than the prior year.

As at 31 December 2016 the Group had no borrowings or undrawn financing facilities. The Company continues to actively identify and develop funding options in order that it can 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 below.

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 suitable drill rigs, seismic vessels and other integral exploration equipment and services.

Other operational risks

In addition to the risks listed above 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 operations 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

24

DIRECTORS’ REPORT

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 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

On 4 January 2016, FAR announced the SNE-2 appraisal well had completed drilling and evaluation ahead of schedule and it delivered a positive result. A DST of the lower reservoir unit flowed oil at a constrained rate of 8,000 bopd (stabilised) confirming high primary reservoir deliverability. A DST of an upper reservoir unit flowed oil at a maximum rate of ~1,000

bopd (unstable), highlighting the potential for these upper units to make a material contribution to SNE resource and production volumes. New SNE-2 data, plus analysis of new and reprocessed seismic and well data, and further appraisal activity is expected to lead to a future revision of the SNE field resource estimates.

On 8 February 2016, FAR announced that an Independent Resources Report completed by RISC for FAR’s SNE oil discovery, offshore Senegal. The report was prepared as at December 2015 incorporating data available from the SNE-1 and FAN-1 discovery wells only and reprocessed 3D seismic. The key conclusion of this report was an upgrade to the SNE oil field contingent recoverable resources (100% basis, recoverable) to 1C: 240 mmbbls (prior 150 mmbbls), 2C: 468 mmbbls (prior 330 mmbbls), 3C: 940 mmbbls (prior 670 mmbbls).

On 9 March 2016, FAR announced successful completion of the SNE-3 appraisal well. Two drill stem tests (DST) confirmed the deliverability of the upper reservoir units and ability to flow at commercially viable rates. A gross 15 metre zone flowed at a maximum rate of 5,400 barrels of oil per day (bopd) and a stabilised main flow rate of 4,000 bopd (56/64” choke). An additional gross 5.5 metre zone, combined with the first flow, produced at a stabilised flow rate of 4,500 bopd (56/64” choke). Flow rates were equipment constrained, exceeded FAR pre-drill expectations, and confirmed reservoir quality and correlation between existing wells. Reservoir units were also intersected shallower to prognosis suggesting the field extends further south than previously mapped. The encouraging SNE-3 results are expected to support a further upgrade of SNE field resource estimates.

On 11 April 2016, FAR announced the BEL-1 well was successfully drilled and discovered gas in the overlying Bellatrix exploration prospect and also confirmed good quality oil reservoir sands and oil column in the deeper appraisal part of the well in the northern portion of the SNE field. The overlying BEL-1 exploration well confirmed two good quality gas bearing sandstone reservoirs in lower zones (8m net) with upper zones interpreted to be tight. No water-bearing units were encountered, implying potential for down-dip oil with extensive structural closure. The deeper appraisal part of the well into the SNE oil field extended the reservoirs in the northern area of the field and confirmed good quality reservoir sands, oil column (100m gross) and 32° API oil quality.

On 13 April 2016, FAR announced the results of an updated Independent Resources Report completed by RISC for FAR’s SNE oil discovery, offshore Senegal. This report followed results of the SNE-2 and SNE-3 appraisal wells and final reprocessed 3D seismic data. The key conclusion of this report was an upgrade to the SNE oil field contingent recoverable resources (100% basis, recoverable) to 1C: 277 mmbbls (prior 240 mmbbls), 2C: 561 mmbbls (prior 468 mmbbls), 3C: 1071 mmbbls (prior 940 mmbbls).

On 19 May 2016, FAR announced successful completion of the SNE-4 appraisal well that further confirmed the scale and extent of the SNE field resource. SNE-4 extended reservoirs in the eastern portion of the SNE field 5km east and down dip from the SNE-3 well location. It demonstrated the presence and correlation of principal reservoir units between each of the wells across the field, confirmed oil bearing upper reservoir sands of similar quality to those encountered as gas bearing elsewhere in the field, oil column (102m gross) and 32° API oil quality.

2016 FAR Annual Report 25

On 23 August 2016, FAR announced the results of a further updated Independent Resources Report completed by RISC for FAR’s SNE oil discovery, offshore Senegal. This report followed results of the BEL-1 and SNE-4 appraisal wells. The key conclusion of this report was an upgrade to the SNE oil field contingent recoverable resources (100% basis, recoverable) to 1C: 348 mmbbls (prior 270 mmbbls), 2C: 641 mmbbls (prior 561 mmbbls), 3C: 1128 mmbbls (prior 1071 mmbbls). The RISC report is to be updated in the future as data from new wells drilled into the SNE field becomes available.

On 1 September 2016, FAR announced that it had determined the Minimum Economic Field Size (MEFS) for a commercial development at SNE had been achieved in only 21 months from the initial SNE-1 discovery well. The MEFS for the SNE project was estimated to be approximately 200 mmbbls. The Operator (Cairn Energy) has reported economic scenarios for a standalone SNE development project that highlight SNE is a robust project with a breakeven oil price estimated at US$35/bbl.

On 25 November 2016, FAR announced the Senegal joint venture had completed an extensive rig tender evaluation process and executed contracts for the use of the Stena DrillMAX drillship for a firm two well drilling program on the SNE field commencing in 1Q 2017. The Senegal joint venture has taken advantage of favourable market conditions and reduced deep water rig rates to secure the Stena DrillMAX drill ship at a highly competitive operational day rate, significantly lower than previously achieved with the Ocean Rig Athena.

At year end the Senegal joint venture was progressing pre-FEED activities focused on determining the final project size and scope in preparation for submission of a development plan for the SNE field to the Senegal Government along with finalising plans to drill two appraisal wells in the SNE field

Guinea-Bissau

The Guinea-Bissau joint venture has acquired, processed and interpreted additional 3D seismic data to evaluate the western shelf edge margin of the large Atum prospect, potentially analogous to the SNE Oil discovery. Joint venture technical meetings are taking place and discussions are progressing with the regulator in relation to an extension to the current licence requiring a well to be drilled by the end of 2019

Kenya L6

FAR continued discussions with the Government of Kenya over 2016 to secure suitable arrangements pursuant to the Petroleum Sharing Contract to allow exploration activity that has been hindered by past security incidents and land access issues, to commence. FAR is planning for a 2D seismic survey to commence as soon as possible.

Kenya L9

During the December quarter, FAR was informed by Ophir Energy, the L9 permit Operator, that it had relinquished the L9 permit.

Australia

FAR received the final processed 3D seismic data over 62% of WA-458-P and is planning to acquire new seismic over the remainder. FAR intends to farm-down its high interest in WA-458-P. FAR has submitted a relinquishment request to the regulator of WA-457-P and intends to leave the permit in good standing.

Subsequent events

On 21 January 2017, FAR commenced drilling the SNE-5 appraisal well and on 8 March 2017 FAR announced SNE-5 was completed 21 days ahead of schedule and significantly below budget. The oil column thickness in SNE-5 was confirmed at 100m gross, as seen at all other SNE oil field wells to date, and it also confirmed reservoir quality and correlation of the principal reservoir units. Overall, SNE-5 flow rates were in line with, or exceeded, pre-drill expectations and a previously untested reservoir section was better than expected:

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.

DST 1b: an additional, 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.

Prior to SNE-5 being plugged and abandoned, pressure gauges were installed over the tested reservoir units in preparation for the planned SNE-6 appraisal well and completion of an interference test. Prior to drilling SNE-6, the Senegal joint venture elected to drill the VR-1 well, located within the SNE oil field approximately 5km to the west of the SNE-1 discovery. The VR-1 well is being drilled to assess the potential for additional lower reservoir within the western part of the SNE field. In addition, the well will examine deeper Aptian carbonate exploration targets under the SNE field (reference ASX announcement 8 March 2017) . Mobilisation of the drill ship to the VR-1 location commenced on completion of SNE-5 operations and the VR-1 well spudded on 9 March.

On 7 February 2017, FAR announced an updated Independent Resources Report for FAR on the exploration potential of the Rufisque, Sangomar and Sangomar Deep (RSSD) blocks, offshore Senegal has been completed by RISC Operations Pty Ltd (‘RISC’). This report has highlighted 1,563 mmbbls of prospective resources, of which 234 mmbbls are net to FAR who is a 15% participant in the joint venture. In addition to the undrilled prospects, the 2C recoverable resource in the SNE discovery is 641 mmbbls with 96 mmbbls net to FAR (reference ASX announcement 23 August 2016).

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 and company secretary 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.

26

DIRECTORS’ REPORT

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 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 4 4 3 3 4 4 2 2 2 2
C M Norman 4 4 - - - - - - 2 2
B J M Clube 4 4 - - - - - - 2 2
R G Nelson 4 4 3 3 4 4 2 2 2 2
A E Brindal 4 4 3 3 4 4 2 2 2 2
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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.

No amounts were paid or payable to the auditor for non-audit services provided during the year by the auditor as outlined in Note 26 to the financial statements.

AUDITOR’S INDEPENDENCE DECLARATION

The auditor’s independence declaration is included on page 38 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 for the financial year ended 31 December 2016. 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 below 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

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	Non-Executve Director
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 Business Development

2016 FAR Annual Report 27

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

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 A E Brindal, each of whom are non-executive directors and considered by the Company to be independent.

Objectives

The objectives of the remuneration Committee are defined 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.

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 Executive 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 Period of directorship Company
Managing	50% 25% 25%
Director
Executve	50% 25% 25%
Director
Senior	50% 25% 25%
executves

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.

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DIRECTORS’ REPORT

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.

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|||||||
|---|---|---|---|---|---|
|31 Dec 2016|31 Dec 2015|31 Dec 2014|31 Dec 2013|31 Dec 2012|
|$|(restated)|
|$|$|$|$|
|Revenue|165,777|287,088|629,293|583,210|1,192,665|
|Loss from continuing operations|(21,759,974)|(19,620,114)|(6,937,168)|(7,955,349)|(14,474,951)|
|Loss from continuing & discontinued operations|(21,759,974)|(19,620,114)|(6,937,168)|(7,957,039)|(14,422,029)|
|31 Dec 2016|31 Dec 2015|31 Dec 2014|31 Dec 2013|31 Dec 2012|
|Share price at start of year|8.3 cents|8.6 cents|4.0 cents|3.4 cents|2.8 cents|
|Share price at end of year|7.5 cents|8.3 cents|8.6 cents|4.0 cents|3.4 cents|
|Dividend|-|-|-|-|-|
|Basic loss per share|(0.52) cps|(0.57) cps|(0.26) cps|(0.32) cps|(0.60) cps|
|Diluted loss per share|(0.52) cps|(0.57) cps|(0.26) cps|(0.32) cps|(0.60) cps|

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The year ended 31 Dec 2012 has been restated to reflect a change in accounting policy in respect of the treatment of exploration expenditure adopted by the Board during the 2013 year.

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, 5.1.1 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.

In recognition of the low oil price environment the Company did not set Key Performance Indicators for the year and did not pay any STI’s in respect of the year ended 31 December 2016.

3.4 Long Term Incentives

Long Term Incentives (‘LTI’) are ‘at risk’ performance based 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.

For further details refer to section 5.1 and 5.2.

2016 FAR Annual Report 29

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. Due consideration is given 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

• Continuous service

• 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 50th percentile and 75th percentile for Relative TSR.

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 preceding 1 February 2016

• 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:

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

CAGR = Compound Annual Growth

Relative TSR

• Number of rights calculated using the 20-day VWAP of the FAR share price preceding 1 February 2016

• 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 vestng 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 2016, 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 sharebased 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.

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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 Ongoing, no fixed term 12 months 2 months
P A Thiessen Ongoing, no fixed term 12 months 2 months
P J Nicholls Ongoing, no fixed term By giving notice of a breach
of contract
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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

2016 Short-term employee benefts Post- employment Share-based payment Long service leave	Total
Name Salary and fees Bonus Non- monetary Super Optons / Rights
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 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

2015 Short-term employee benefts Post- employment Share-based payment Long service leave	Total
Name Salary and fees Bonus Non- monetary Super Optons / Rights
C M Norman 520,000 - - 30,000 163,333 14,079	727,412
B J M Clube 445,000 - - 30,000 130,667 6,425	612,092
P J Nicholls(i) 447,300 - - - 130,667 -	577,967
G A Ramsay(ii) 380,417 - - 32,083 130,667 1,033	544,200
P A Thiessen 250,000 - - 30,000 130,667 2,418	413,085
	2,874,756

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

(ii) G A Ramsay was appointed Executive General Manager Business Development on 1 February 2015

2016 FAR Annual Report 31

5.1.1 Actual pay

The table below provides a summary of actual remuneration paid to the Executives in the 2016 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 Accounting Standards are presented in 5.1 Remuneration table

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2016 Salary and fees Super 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 422,062 35,000 457,062
P A Thiessen 270,262 30,000 300,262
2,250,798
2015 Salary and fees Super Total
C M Norman 520,000 30,000 550,000
B J M Clube 445,000 30,000 475,000
P J Nicholls 447,300 - 447,300
G A Ramsay 380,417 32,083 412,500
P A Thiessen 250,000 30,000 280,000
2,164,800
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5.2 Analysis of Short term incentives

For further details on short term incentives see section 3.3 above.

In recognition of the low oil price environment the Company did not set Key Performance Indicators for the year and did not pay any STI’s in respect of the year ended 31 December 2016.

5.3 Analysis of Long term incentives

For further details on long term incentives see section 3.4 above.

During the year the Company granted Performance Rights under the Performance Rights Plan. The Company did not grant any options under the Executive Incentive Plan during the year.

Performance against the absolute and relative TSR criteria in respect of the Performance Rights will be measured at the end of the performance period at 31 January 2019.

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:

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Number of
rights granted Grant Fair value Total Exercise price Expiry
during the year [1] date per right [2] value per right date [4]
C M Norman [3] 3,578,000 20-May-16 0.055 196,790 $0.00 31-Jan-19
B J M Clube [3] 3,090,000 20-May-16 0.055 169,950 $0.00 31-Jan-19
P J Nicholls 2,800,000 20-May-16 0.055 154,000 $0.00 31-Jan-19
G A Ramsay 2,928,000 20-May-16 0.055 161,040 $0.00 31-Jan-19
P A Thiessen 1,923,000 20-May-16 0.055 105,765 $0.00 31-Jan-19
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1. 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 which represents the 20 day VWAP preceding 1 February 2016.

2. The fair value per right granted represents the valuation for rights granted and calculated at grant date.

3. 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.

4. The performance period is from 1 February 2016 to 31 January 2019.

32

DIRECTORS’ REPORT

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 [(i)] - 3,578,000 - - - 3,578,000
B J M Clube [(i)] - 3,090,000 - - - 3,090,000
P J Nicholls - 2,800,000 - - - 2,800,000
- - - -
G A Ramsay 2,928,000 2,928,000
P A Thiessen - 1,923,000 - - - 1,923,000
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(i) 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.

The absolute 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 2016 at $0.078 per Share, which is the 20 day volume weighted average price (VWAP) preceding 1 February 2016. Performance against this criteria will be measured at the end of the performance period, 31 January 2019.

The relative 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 2019.

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 of the executives during the financial year were as follows:

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Options series Grant Grant date Exercise Expiry Vesting Vesting
date fair value price date percentage date
Series 10 27 May 2013 1.6 cents 4.4 cents 27 May 2016 100% Vested on 27 May 2013
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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1. 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 Senegal joint operation Operator was met. None of these options have been exercised.

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 2016 1 Jan 16 Remuneration Exercised Change 31 Dec 16
Directors
C M Norman [1] 24,000,000 - (14,000,000) - 10,000,000
B J M Clube [1] 20,000,000 - (12,000,000) - 8,000,000
N J Limb [1] 5,000,000 - (5,000,000) - -
R G Nelson [1] 5,000,000 - - - 5,000,000
Key Executives
P J Nicholls 18,000,000 - (10,000,000) - 8,000,000
P A Thiessen 8,000,000 - - - 8,000,000
- -
G A Ramsay 14,000,000 (6,000,000) 8,000,000
- -
94,000,000 (47,000,000) 47,000,000
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2016 FAR Annual Report 33

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For the year ended Balance Granted as Net Other Balance
31 Dec 2015 1 Jan 15 Remuneration Exercised Change 31 Dec 15
Directors
C M Norman [1] 34,000,000 10,000,000 (20,000,000) - 24,000,000
B J M Clube [1] 22,000,000 8,000,000 (10,000,000) - 20,000,000
N J Limb 5,000,000 - - - 5,000,000
R G Nelson - 5,000,000 - - 5,000,000
Key Executives
P J Nicholls 20,000,000 8,000,000 (10,000,000) - 18,000,000
P A Thiessen - 8,000,000 - - 8,000,000
-
G A Ramsay 12,000,000 8,000,000 (6,000,000) 14,000,000
-
93,000,000 47,000,000 (46,000,000) 94,000,000
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1. Grants of options to C M Norman, N J Limb, B J M Clube and R G Nelson were approved by shareholders at Annual General Meetings of prior years.

During the year, the Managing Director, Executive Director and Senior Executives exercised options that were granted to them as part of their compensation. Each option converts into one ordinary share of FAR Ltd.

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No. of No. of ordinary Value of Value of
options shares of FAR options granted options at Amount Amount
Name exercised Ltd issued at grant date exercise date paid unpaid
C M Norman 14,000,000 14,000,000 2.5 cents 742,000 $616,000 $nil
B J M Clube 12,000,000 12,000,000 2.5 cents 492,000 $528,000 $nil
N J Limb 5,000,000 5,000,000 2.5 cents 205,000 $220,000 $nil
P J Nicholls 10,000,000 10,000,000 2.5 cents 410,000 $440,000 $nil
P A Thiessen 6,000,000 6,000,000 2.5 cents 246,000 $264,000 $nil
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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.

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For the year ended Balance Received on Exercise Net Other Balance
31 Dec 2016 1 Jan 16 of Options Change [(iv)] 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 350,955 - - 350,955
R G Nelson [(ii)] 500,000 - - 500,000
Key Executives
P J Nicholls 4,543,291 10,000,000 (5,430,000) 9,113,291
- -
G A Ramsay [(iiI)] 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
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34

DIRECTORS’ REPORT

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For the year ended Balance Received on Exercise Net Other Balance
31 Dec 2015 1 Jan 15 of Options Change [(iv)] 31 Dec 15
Directors
C M Norman 574,417 20,000,000 (15,900,327) 4,674,090
B J M Clube 1,920,000 10,000,000 (188,000) 11,732,000
N J Limb 32,908,139 - 2,000,000 34,908,139
C L Cavness [(i)] 1,150,000 - (1,150,000) -
A E Brindal 311,061 - 39,894 350,955
R G Nelson [(ii)] - - 500,000 500,000
Key Executives
P J Nicholls 4,543,291 10,000,000 (10,000,000) 4,543,291
- -
G A Ramsay [(iiI)] 550,000 550,000
P A Thiessen - 6,000,000 (4,937,500) 1,062,500
41,406,908 46,000,000 (29,085,933) 58,320,975
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• (i) C L Cavness resigned as a director on 15 May 2015.

• (ii) R G Nelson was appointed a director on 9 April 2015.

• (iii) G A Ramsay was appointed Executive General Manager Business Development (EGMBD) on 1 February 2015.

(iv) Represents shares sold except for C L Cavness, R G Nelson and G A Ramsay in 2015 year. C L Cavness shares removed from table upon resignation of directorship, R G Nelson shares acquired subsequent to his appointment as director and G A Ramsay shares acquired subsequent to appointment as EGMBD.

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$350,000 per annum in accordance with the Company’s constitution and as approved by shareholders at the Annual General Meeting held in May 2013.

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.

• No additional fees are paid for participation on any Board committees.

• 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.

2016 FAR Annual Report 35

2016	Short-term employee benefts	Short-term employee benefts	Short-term employee benefts	Post-	Share-based	Long service	Total
				employment	payment	leave
Name	Salary	Bonus	Non-	Super	Optons /
	and fees		monetary		Rights(ii)
Non-Executve	Directors
N J Limb	150,000		-	- -		-	- 150,000
A E Brindal	50,000		-	- -		-	- 50,000
R G Nelson	68,493		-	- 6,507	163,333		- 238,333
2015	Short-term employee benefts			Post-	Share-based	Long service	Total
				employment	payment	leave
Name	Salary	Bonus	Non-	Super	Optons /
	and fees		monetary		Rights(ii)
Non-Executve	Directors
N J Limb	150,000		-	- -		-	- 150,000
A E Brindal	50,000		-	- -		-	- 50,000
C L Cavness(i)	20,833		-	- -		-	- 20,833
R G Nelson	49,658		-	- 4,717	81,667		- 136,042

(i) C L Cavness resigned as a director on 15 May 2015

(ii) Shareholders approved the grant of 5,000,000 options to R G Nelson at the Annual General Meeting held on 15 May 2015.

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, 22 March 2017

36

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FINANCIAL
REPORT 2016
FAR MOVES INTO 2017 WITH
A ROBUST CASH POSITION
LARGELY DRIVEN BY THE
REDUCTION IN DEEPWATER
DRILLING COSTS
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2016 FAR Annual Report 37

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 Australia

Tel: +61 (0) 3 9671 7000 Fax: +61 (0) 3 9671 7001! www.deloitte.com.au

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

22 March 2017

Dear Board Members

FAR Limited

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

As lead audit partner for the audit of the financial statements of FAR Limited for the financial year ended 31 December 2016, 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

DELOITTE TOUCHE TOHMATSU

Ryan Hansen Partner Chartered Accountants

Liability limited by a scheme approved under Professional Standards Legislation.

Member of Deloitte Touche Tohmatsu Limited

38

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 Australia

Tel: +61 (0) 3 9671 7000 Fax: +61 (0) 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 2016, 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 of the consolidated entity, comprising the Company and the entities it controlled at the year then ended or from time to time during the financial year as set out on pages 43 to 74.

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 2016 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.

2016 FAR Annual Report 39

INDEPENDENT AUDITOR’S REPORT

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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.

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 2016 the Group incurred $41.1 million in exploration and evaluation (E&E) costs during the period, of which $24.7 million has been capitalised and all other E&E costs were expensed as disclosed in note 3(p). Significant judgement is required 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:

• Obtaining an understanding of 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 related disclosures in note 11 to the financial statements.

Recoverability of exploration and evaluation assets

As at 31 December 2016 the carrying amount of E&E assets is $101.7 million (2015: $58.9 million), as disclosed in note 11.

Significant judgement is applied in determining whether facts and circumstances indicate that the exploration and expenditure assets should be tested for impairment in accordance with Australian Accounting Standard AASB 6 Exploration for and Evaluation of Mineral Resources.

Our audit procedures included but were not limited to:

• Obtaining an understanding of 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 consideration of the facts and circumstances 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,

• Obtaining an understanding of 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

• Challenging management to understand 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 related disclosures in note 11 to the financial statements.

40

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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 2016, 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.

2016 FAR Annual Report

41

INDEPENDENT AUDITOR’S REPORT

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• 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.

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 of FAR Limited included in pages 27 to 36 of the directors’ report for the year ended 31 December 2016.

In our opinion, the Remuneration Report of FAR Limited, for the year ended 31 December 2016, 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.

DELOITTE TOUCHE TOHMATSU

Ryan Hansen Partner Chartered Accountants Melbourne, 22 March 2017

42

DIRECTORS’ DECLARATION

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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, 22 March 2017

2016 FAR Annual Report 43

CONSOLIDATED STATEMENT OF PROFIT OR LOSS AND OTHER COMPREHENSIVE INCOME

For the financial year ended 31 December 2016

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|||||
|---|---|---|---|
|Year ended|Year ended|
|31 Dec 2016|31 Dec 2015|
|Note|AU$|AU$|
|Interest income|165,777|287,088|
|Depreciation expense|6|(41,033)|(44,327)|
|Exploration expense|(16,352,405)|(16,674,745)|
|Corporate Administration expenses|(767,614)|(635,823)|
|Employee benefits expense|6|(4,612,423)|(3,102,003)|
|Corporate Consulting expense|(513,550)|(545,157)|
|Foreign exchange gain|767,004|1,333,165|
|Other expenses|(405,730)|(238,312)|
|Loss before income tax|(21,759,974)|(19,620,114)|
|Income tax expense|7|-|-|
|LOSS FOR THE YEAR|(21,759,974)|(19,620,114)|
|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|1,654,452|3,473,530|
|Other comprehensive gain for the year, net of the income tax|1,654,452|3,473,530|
|TOTAL COMPREHENSIVE LOSS FOR THE YEAR|(20,105,522)|(16,146,584)|
|Earnings per share:|
|From continuing operations|
|Basic loss (cents per share)|15|(0.52)|(0.57)|
|Diluted loss (cents per share)|15|(0.52)|(0.57)|

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Notes to the financial statements are included on pages 48 to 74.

44

CONSOLIDATED STATEMENT OF FINANCIAL POSITION

As at 31 December 2016

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|||||
|---|---|---|---|
|Year ended|Year ended|
|Note|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|CURRENT ASSETS|
|Cash and cash equivalents|20(a)|46,978,179|60,670,897|
|Trade and other receivables|8|2,575,664|1,841,315|
|Other financial assets|9|120,299|116,007|
|Total Current Assets|49,674,142|62,628,219|
|NON CURRENT ASSETS|
|Property, plant and equipment|10|319,467|346,186|
|Exploration and evaluation assets|11|101,706,766|58,861,246|
|Total Non-Current Assets|102,026,233|59,207,432|
|TOTAL ASSETS|151,700,375|121,835,651|
|CURRENT LIABILITIES|
|Trade and other payables|12|5,958,709|18,761,407|
|Provisions|13|885,571|696,155|
|Total Current Liabilities|6,844,280|19,457,562|
|NON-CURRENT LIABILITIES|
|Provisions|13|55,870|89,819|
|Total Non-Current Liabilities|55,870|89,819|
|TOTAL LIABILITIES|6,900,150|19,547,381|
|NET ASSETS|144,800,225|102,288,270|
|EQUITY|
|Issued Capital|14|297,933,534|237,806,280|
|Reserves|12,527,406|8,382,731|
|Accumulated losses|(165,660,715)|(143,900,741)|
|TOTAL EQUITY|144,800,225|102,288,270|

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Notes to the financial statements are included on pages 48 to 74.

2016 FAR Annual Report 45

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the financial year ended 31 December 2016

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|||||||||||
|---|---|---|---|---|---|---|---|---|---|
|Reserves|
|Equity|Foreign|Total|
|Share based|component|currency|attributable to|
|payments|on convertible|translation|Accumulated|equity holders|
|Share capital|reserve|[(i)]|notes|[(ii)]|reserve|[(iii)]|Total|losses|of the parent|
|AU$|AU$|AU$|AU$|AU$|AU$|AU$|
|Balance at|
|1 January 2015|195,770,263|4,844,555|671,496|(1,046,021)|4,470,030|(124,952,123)|75,288,170|
|-|-|-|-|-|
|Loss for the year|(19,620,114)|(19,620,114)|
|Other Comprehensive|
|income for the year,|
|net of income tax|-|-|-|3,473,530|3,473,530|-|3,473,530|
|Total comprehensive|
|-|-|-|
|income for the year|3,473,530|3,473,530|(19,620,114)|(16,146,584)|
|Recognition of|
|-|-|-|-|
|share-based payments|1,110,667|1,110,667|1,110,667|
|-|-|-|-|-|
|Issue of ordinary shares|40,027,333|40,027,333|
|Transfer|-|-|(671,496)|-|(671,496)|671,496|-|
|Issue of ordinary shares|
|-|-|-|-|-|
|under share option plan|3,990,000|3,990,000|
|Share issue costs|(1,981,316)|-|-|-|-|-|(1,981,316)|
|Balance at|
|31 December 2015|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/loss for the year|1,654,452|1,654,452|(21,759,974)|(20,105,522)|
|Recognition 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 option 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|

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

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

(ii) The equity component on convertible notes represents the equity component on the historical issue of unsecured convertible notes.

(iii) 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 48 to 74.

46

CONSOLIDATED STATEMENT OF CASH FLOWS

For the financial year ended 31 December 2016

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|||||
|---|---|---|---|
|Year ended|Year ended|
|31 Dec 2016|31 Dec 2015|
|Note|AU$|AU$|
|CASH FLOWS FROM OPERATING ACTIVITIES|
|Payments to suppliers and employees|(3,643,675)|(3,288,953)|
|Payments for exploration and evaluation expensed|(17,129,854)|(15,829,833)|
|Net cash used in operating activities|20(d)|(20,773,529)|(19,118,786)|
|CASH FLOWS FROM INVESTING ACTIVITIES|
|Interest received|154,242|361,279|
|Payments for exploration and evaluation assets capitalised|(53,807,962)|(32,063,725)|
|Payments for property, plant and equipment|(56,208)|(270,395)|
|-|
|Advance from / (to) Joint Operation|45,657|
|-|
|Payment of performance bonds|(31,250)|
|Net cash used in investing activities|(53,709,928)|(31,958,434)|
|CASH FLOWS FROM FINANCING ACTIVITIES|
|Proceeds from issue of shares|62,728,000|44,017,333|
|Payment for share issue costs|(2,600,746)|(1,981,316)|
|Net cash provided by financing activities|60,127,254|42,036,017|
|NET (DECREASE) / INCREASE IN CASH AND CASH EQUIVALENTS|(14,356,203)|(9,041,203)|
|Cash and cash equivalents at the beginning of the year|60,670,897|67,225,297|
|Effects of exchange rate changes on cash and cash equivalents|663,485|2,486,803|
|Cash and cash equivalents at the end of the financial year|20(a)|46,978,179|60,670,897|

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

Notes to the financial statements are included on pages 48 to 74.

2016 FAR Annual Report

47

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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

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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 2016.

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

The directors note that the impact of the initial application of the Standards and Interpretation is not yet known or is not reasonably estimable and is currently being assessed. 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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|||||
|---|---|---|---|
|Mandatory beyond 31 December 2016|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 2016-1|Amendments to Australian Accounting Standards – Recognition of Deferred Tax Assets|
|for Unrealised Losses|1 Jan 2017|
|–|
|AASB 2016-2 Amendments to Australian Accounting Standards|Disclosure Initiative: Amendments|
|to AASB 107|1 Jan 2017|
|–|
|AASB 2016-5 Amendments to Australian Accounting Standards|Classification and Measurement of|
|Share-based Payment Transactions|1 Jan 2018|
|AASB 2017-2|Amendments to Australian Accounting Standards – Further Annual Improvements|
|2014-2016 Cycle|1 Jan 2017|
|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, no IASB Standards and IFRIC Interpretations were in issue but not yet effective, although Australian equivalent Standards and Interpretations have not yet been issued.

48

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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 22 March 2017.

(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 2016, the Group’s current assets exceeded current liabilities by $42,829,862 and the Group has cash and cash equivalents of $46,978,179. 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 require funding within the next twelve months to fund further exploration and appraisal drilling in Senegal, seismic in 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 that 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; and

• The option of relinquishing or disposing of rights and interests in certain assets.

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 17, 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;

• 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.

2016 FAR Annual Report 49

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

(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.

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(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

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.

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.

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.

50

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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.

2016 FAR Annual Report 51

For the financial year ended 31 December 2016

NOTES TO THE FINANCIAL STATEMENTS

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.

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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.

52

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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.

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 2016|31 Dec 2015|31 Dec 2016|31 Dec 2015|
|AU$|AU$|AU$|AU$|
|Guinea-Bissau|1,278,206|1,483,114|18,765|83,743|
|Kenya|1,176,802|775,312|16,389|46,808|
|Senegal|102,561,602|69,385,449|5,392,889|17,790,502|
|Other|[(i)]|9,536|117,346|4,773|4,727|
|Corporate|46,674,229|50,074,430|1,467,334|1,621,601|
|Total assets and liabilities|151,700,375|121,835,651|6,900,150|19,547,381|

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(i) During the year, the AGC segment has been reallocated to Other as the threshold does not meet the quantitative threshold of AASB 8 and the chief operating decision maker does not view this segment as significant with respect to the Group.

2016 FAR Annual Report 53

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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Segment Revenue and Results

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

Interest Year ended 31 Dec 2016 AU$	Income Segment Loss Year ended 31 Dec 2015 AU$ Year ended 31 Dec 2016 AU$ Year ended 31 Dec 2015 AU$	Income Segment Loss Year ended 31 Dec 2015 AU$ Year ended 31 Dec 2016 AU$ Year ended 31 Dec 2015 AU$
Australia -	- (957,104)	(1,363,424)
Guinea-Bissau -	- (1,085,706)	(1,377,989)
Kenya -	- (341,388)	(297,183)
Senegal -	- (13,452,226)	(12,611,392)
Other 302	314 (520,727)	(1,029,847)
Corporate 165,475	286,774 (5,402,823)	(2,940,279)
Total for contnuing operatons 165,777	287,088 (21,759,974)	(19,620,114)
Income tax expense		-
Loss before tax (contnuing operatons)	(21,759,974)	(19,620,114)

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

Other segment information

Other segment informaton	Other segment informaton
Depreciaton Additons to Non-Current Assets Year ended 31 Dec 2016 AU$ Year ended 31 Dec 2015 AU$ Year ended 31 Dec 2016 AU$ Year ended 31 Dec 2015 AU$
Guinea-Bissau -	- (355,336)(i) 344
Kenya -	- 1,655 5,905
Senegal -	- 42,637,856 20,546,412
Corporate 41,033	44,327 56,207 270,395
Total 41,033	44,327 42,340,382 20,823,056

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

54

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6. 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 2016|31 Dec 2015|
|AU$|AU$|
|Depreciation:|
|- Property, plant & equipment|(82,926)|(77,619)|
|- Recharge of depreciation to exploration expenditure|41,893|33,292|
|(41,033)|(44,327)|
|Exploration Expense:|
|- AGC|-|(2,203)|
|- Australia|(957,104)|(1,363,424)|
|- Guinea-Bissau|(1,085,706)|(1,377,989)|
|- Senegal|(13,452,226)|(12,611,392)|
|- Kenya|(341,388)|(297,183)|
|- Other|(515,981)|(1,022,554)|
|(16,352,405)|(16,674,745)|
|Consulting expenses:|
|- Corporate and other consulting costs|(513,550)|(545,157)|
|(513,550)|(545,157)|
|Employee benefit expense:|
|- Short-term employee benefits – salaries and fees|(2,871,556)|(2,737,659)|
|- Recharge of salaries and fees to exploration expenditure|1,101,010|1,099,030|
|Post-employment benefits:|
|- Defined contribution plans|(196,188)|(193,879)|
|- Share based payments-equity settled – non cash|(2,490,223)|(1,110,667)|
|- Increase in employee benefits provisions|(155,466)|(158,828)|
|(4,612,423)|(3,102,003)|

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2016 FAR Annual Report 55

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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7. INCOME TAXES

(a) Income tax recognised in profit or loss

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||||
|---|---|---|
|Year ended|Year ended|
|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|Tax (income) comprises:|
|Current tax expense|(1,156,857)|(487,197)|
|Tax losses not brought to account|1,156,857|487,197|
|Deferred tax (income) relating to the origination and reversal of temporary differences|(49,444)|(794,066)|
|Benefit arising from previously recognised tax losses of prior periods used to reduce|
|deferred tax expense|49,444|794,066|
|Prior year unders / overs|522,734|(104,848)|
|Utilisation of previously unrecognised tax losses|(522,734)|104,848|
|-|-|
|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 2016|31 Dec 2015|
|AU$|AU$|
|Loss from operations|(21,759,974)|(19,620,114)|
|Income tax (income) calculated at 30%|(6,527,992)|(5,886,034)|
|Non-deductible expenses|5,398,346|4,885,230|
|Non-assessable gains / (loss)|267,508|596,398|
|Recognition of previously unrecognised deductible temporary differences|(294,719)|(82,791)|
|Unused tax losses and tax offsets not recognised as deferred tax assets|1,156,857|487,197|
|-|-|

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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|
|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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|||||
|---|---|---|---|
|Recognised|Closing|
|Opening balance|in income|balance|
|2015|AU$|AU$|AU$|
|Property, plant & equipment|(841)|346|(495)|
|Receivables|(22,842)|(374,680)|(397,522)|
|Payables|16,885|1,693|18,578|
|Provisions|185,634|50,158|235,792|
|Total|178,836|(322,483)|(143,647)|

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||||
|---|---|---|
|31 Dec 2016|31 Dec 2015|
|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)|
|Tax losses in the United States (net)|4,730,863|4,683,844|
|Tax losses in Australia (net)|14,489,170|12,809,579|
|Capital losses in Australia|99,257|99,257|
|19,319,290|17,592,680|

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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.

2016 FAR Annual Report 57

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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8. TRADE AND OTHER RECEIVABLES

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|||||
|---|---|---|---|
|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|Current|
|Interest receivable|9,806|1,942|
|Other receivables|749,255|348,467|
|Prepayments|177,377|167,773|
|Joint operation receivables|[ (i)]|1,639,226|1,323,133|
|2,575,664|1,841,315|

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(i) Includes Senegal joint operation receivables of $1,494,224 (2015: $1,185,330).

9. OTHER FINANCIAL ASSETS

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||||
|---|---|---|
|31 Dec 2016|31 Dec 2015|
|Current|AU$|AU$|
|Joint operation security deposit|1,640|985|
|Joint operation performance bond|118,659|115,022|
|120,299|116,007|

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The weighted average interest rate on the performance bond is 1.88% (2015: 2.83%).

10. PROPERTY, PLANT AND EQUIPMENT

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||||
|---|---|---|
|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|Furniture, Fittings & Equipment Cost|
|Balance at 1 January|783,137|512,742|
|Additions|56,207|270,395|
|Balance at 31 December|839,344|783,137|
|Accumulated depreciation and impairment|
|Balance at 1 January|436,951|359,332|
|Depreciation expense|82,926|77,619|
|Balance at 31 December|519,877|436,951|
|Net Book Value|319,467|346,186|

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58

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11. EXPLORATION AND EVALUATION ASSETS

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|||||
|---|---|---|---|
|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|Exploration and evaluation expenditure:|
|Balance at 1 January|58,861,246|34,124,907|
|Additions|[(i)]|42,284,176|20,552,661|
|Net foreign currency exchange differences|[(i)]|561,344|4,183,678|
|Balance at 31 December|101,706,766|58,861,246|

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(i) During the 2016 year the Company with its Senegal joint operation partners Capricorn Senegal Limited (a subsidiary of Cairn Energy PLC) and ConocoPhillips, completed the drilling of 4 wells, SNE-2, SNE-3, BEL-1 and SNE-4 and commenced planning and preparation for the SNE-5 and SNE-6 wells which commenced drilling in January 2017. The Company’s participating share of these costs incurred during the 2016 year was $42,637,856, inclusive of net foreign exchange differences. The 6 successful Senegal wells, FAN-1, SNE-1, SNE-2, SNE-3, SNE-4 and BEL-1 have all been capitalised to exploration and evaluation assets.

12. TRADE AND OTHER PAYABLES

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|||||
|---|---|---|---|
|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|Current|
|Trade payables|[ (i)]|405,936|637,770|
|Other payables|287,615|216,996|
|Joint operation payables|[ (ii)]|5,265,158|17,906,641|
|5,958,709|18,761,407|

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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 $5,205,756 (2015: $17,790,502) 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 2016|31 Dec 2015|
|AU$|AU$|
|Current|
|Employee benefits|885,571|696,155|
|Non-Current|
|Employee benefits|55,870|89,819|

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

2016 FAR Annual Report 59

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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14. ISSUED CAPITAL

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|||||||
|---|---|---|---|---|---|
|31 Dec 2016|31 Dec 2016|31 Dec 2015|31 Dec 2015|
|Number|AU$|Number|AU$|
|Paid up capital:|
|Ordinary fully paid shares|
|at beginning of year|3,693,650,099|237,806,280|3,126,808,427|195,770,263|
|Shares allotted during the year|[ (a)]|767,882,359|62,728,000|566,841,672|44,017,333|
|Share issue costs|-|(2,600,746)|-|(1,981,316)|
|Ordinary fully paid shares at end of year|4,461,532,458|297,933,534|3,693,650,099|237,806,280|

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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) 14,000,000 ordinary fully paid shares were issued at 4.4 cents upon the exercise of unlisted options on 24 March 2016.

• (ii) 556,147,505 ordinary fully paid shares were issued at 8.5 cents per share via a placement to institutional and sophisticated investors on 21 April 2016.

• (iii) 48,000,000 ordinary fully paid shares were issued at 4.4 cents upon the exercise of unlisted options on 27 May 2016.

• (iv) 149,734,854 ordinary fully paid shares were issued at 8.5 cents per share via a placement to institutional and sophisticated investors on 6 June 2016.

Share options outstanding at balance date

See Note 22 share based payments for details of options and Performance Rights outstanding at 31 December 2016.

15. EARNINGS PER SHARE

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||||
|---|---|---|
|31 Dec 2016|31 Dec 2015|
|Cents per share|Cents per share|
|Basic loss per share|
|From continuing operations|(0.52)|(0.57)|
|Diluted loss per share|
|From continuing operations|(0.52)|(0.57)|

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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 2016|31 Dec 2015|
|AU$|AU$|
|Loss:|
|Loss for the year attributable to members of FAR Ltd|(21,759,974)|(19,620,114)|
|(21,759,974)|(19,620,114)|
|Number|Number|
|Weighted average number of ordinary shares for the purposes of basic|
|and diluted loss per share|4,207,584,889|3,431,303,408|

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60

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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 2016|31 Dec 2015|
|Number|Number|
|-|
|4.4 cents May 2016 unlisted options|62,000,000|
|10.0 cents June 2018 unlisted options|68,000,000|68,000,000|
|-|
|0.0 cents May 2016 unlisted Performance Rights|21,425,000|
|89,425,000|130,000,000|

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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 2016|31 Dec 2016|
|AU$|AU$|
|Exploration and evaluation assets|
|Not longer than 1 year|45,710,644|50,606,251|
|-|
|Longer than 1 year and not longer than 5 years|44,196,163|
|-|-|
|Longer that 5 years|
|45,710,644|94,802,414|

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2016 FAR Annual Report 61

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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17. CONTINGENT LIABILITIES

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|||||
|---|---|---|---|
|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|Contingent liabilities|
|Guinea-Bissau – contingent payment from future production|[ (i)]|17,965,727|17,793,594|
|Guinea-Bissau – contingent withholding tax liability|[ (ii)]|784,704|777,185|
|Kenya L6 – Performance Bond|[ (iii)]|118,659|115,022|
|18,869,090|18,685,801|

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(i) In 2009, the Company entered into an Agreement to acquire a 15% 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. Joint venture technical meetings are taking place and discussions are progressing with the regulator in relation to an extension to the current licence requiring a well to be drilled by the end of 2019.

(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 2016 is $784,704.

(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. The security deposit equal to the contingent liability of $118,659 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. In addition to the above, the Kenya L6 joint venture (the Consolidated Entity has a 60% paying interest) has made representations to the Kenyan Revenue Authority relating to the farm-out agreement that the Group had executed with Milio International. The Condition Precedents were not completed as required pursuant to the terms of the farm out agreement. The existence of and amount of a liability has not yet been determined.

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

62

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18. INTERESTS IN JOINT OPERATIONS

The Group has an interest in the following material joint operations whose principal activities are oil and gas exploration:

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|||||
|---|---|---|---|
|Name|Equity Interest|
|31 Dec 2016|31 Dec 2015|
|%|%|
|Guinea-Bissau|
|Sinapa / Esperança|15.0|15.0|
|Kenya|
|L6|[ (i)]|60.0|60.0|
|L9|[(ii)]|-|30.0|
|Senegal|
|Rufisque Offshore / Sangomar Offshore / Sangomar Deep Offshore|15.0|15.0|
|-|-|
|Djiffere Block|[ (iii)]|

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• (i) A farm-out agreement was executed in early 2014 in relation to Block L6 with Milio E&P Limited and Milio International (‘Milio’) a Dubai based oil trading company that operates the neighbouring Block L20 onshore Kenya. Pursuant to the terms of the farm-out agreement, FAR and its L6 partners, Pancontinental Oil & Gas NL Ltd and Afrex Ltd, are to be fully funded through the acquisition, processing and interpretation of an onshore 2D seismic survey and the drilling and testing of a high impact onshore exploration well in Block L6. The drilling of the farm-out well would satisfy the work program and expenditure obligations for the current permit period of the Block L6 PSC. FAR will remain the Operator on record of the entire Production Sharing Contract (‘PSC’) for Block L6. Pursuant to the terms of the farm-out agreement, including Milio fulfilling the required farm-out activities, Milio will earn the rights and an associated 60% beneficial interest in relation to the onshore part of Block L6 only and FAR retains a 24% beneficial interest in the joint venture for the onshore part of Block L6. FAR also preserves its 60% interest in the joint operation for the highly prospective offshore part of Block L6 which FAR has estimated to contain substantial prospective resources. In February 2014, FAR received approval from the Kenyan Ministry of Energy and Petroleum for the farm-out in relation to the onshore portion of Block L6.

Since executing the farm-out agreement, the agreed farm-out work program to be completed by Milio has suffered delays due to civil upheaval and security incidents in the region that arose during 2014. As a result of these incidents, the Ministry of Energy and Petroleum of Kenya awarded the Block L6 joint operation a 12 month extension and is working with the Block L6 joint operation to ensure appropriate access for petroleum operations is established. Due to these circumstances the above mentioned farm out agreement could not be completed between the L6 Parties and Milio International because Milio International was not in a position to fulfil its portion of the obligations in relation to the farm-out agreement and, as such the Conditions Precedents were not completed as required pursuant to the terms of the farm out agreement. As a consequence of these circumstances, Milio International does not currently have a participating interest or any rights in relation to Block L6 and the current Block L6 participants are FAR Ltd (60%) and Pancontinental Oil & Gas NL (40%). The farm-out parties are in discussions in relation to a revised farm-out agreement to reflect the above mentioned changed circumstances.

(ii) Ophir Energy PLC (‘Ophir’), operator of Block L9, relinquished the permit prior to year-end. The carrying value of this asset was nil.

(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. Under it’s agreements with Trace, FAR has the option to earn a 75% working interest in the Djiffere Block by drilling an exploration well before 31 July 2018 or later if the PSC period is extended (subject to Government approvals). FAR’s obligations under it’s agreements with Trace in relation to it’s option have been met and included acquiring new 3D seismic data over the Djiffere Block in late 2015.

2016 FAR Annual Report 63

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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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 2016|31 Dec 2015|
|AU$|AU$|
|Current Assets|
|Cash and cash equivalents|1,066,723|11,348,160|
|Trade and other receivables|1,639,226|1,323,133|
|Other financial assets|120,299|116,007|
|Non-Current Assets|
|Exploration and evaluation assets|101,706,766|58,861,246|
|Current Liabilities|
|Trade and other payables|5,265,158|17,906,641|

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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.

19. SUBSIDIARIES

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||||||
|---|---|---|---|---|
|Ownership interest|
|Country of|2016|2015|
|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|-|
|FAR Holdings 2 Pty Ltd|[ (ii)]|Australia|100|-|
|FAR Meridian Pty Ltd|[ (ii)]|Australia|100|-|
|First Australian Resources, Inc.|USA|100|100|
|Petrole Investments Group Pty Ltd|Mauritius|100|100|
|Meridian Minerals Limited|Mauritius|100|100|
|FAR Mauritius 1 Pty Ltd|Mauritius|100|100|
|FAR Mauritius 2 Pty Ltd|Mauritius|100|100|
|FAR Senegal SARL|Senegal|100|-|
|FAR Senegal RSSD SA|Senegal|100|-|
|FAR Senegal 1 SA|Senegal|100|-|
|FAR Senegal Djiffere SA|Senegal|100|-|

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(i) FAR Ltd 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.

64

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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 2016|31 Dec 2015|
|Statement of profit or loss and other comprehensive income|AU$|AU$|
|Interest income|165,473|286,774|
|Depreciation and amortisation expense|(41,033)|(44,327)|
|Impairment of intercompany loans and investments|(1,934,872)|(1,785,162)|
|Exploration expense|(15,053,913)|(15,032,502)|
|Administration expense|(664,169)|(563,654)|
|Employee benefits expense|(4,612,423)|(3,102,003)|
|Consulting expense|(486,562)|(539,255)|
|Foreign exchange gain|740,536|1,338,022|
|Other expenses|(399,088)|(238,311)|
|Loss before income tax|(22,286,051)|(19,680,418)|
|Income tax expense|
|Loss for the year|(22,286,051)|(19,680,418)|
|Other comprehensive loss|
|Items that may be reclassified subsequently to profit or loss|
|Exchange differences arising on translation of foreign operations|1,716,094|729,715|
|Total comprehensive loss|(20,569,957)|(18,950,703)|

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2016 FAR Annual Report 65

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NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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31 Dec 2016 31 Dec 2015
Statement of Financial Position AU$ AU$
CURRENT ASSETS
Cash and cash equivalents 46,537,066 60,469,881
Trade and other receivables 2,308,162 1,760,158
Total Current Assets 48,845,228 62,230,039
NON CURRENT ASSETS
Trade and other receivables 106,412 108,130
Other financial assets 132 103
Property, plant and equipment 319,467 346,186
Exploration and evaluation assets 101,243,535 58,404,093
Total Non-Current Assets 101,669,546 58,858,512
TOTAL ASSETS 150,514,774 121,088,551
CURRENT LIABILITIES
Trade and other payables 5,908,104 18,684,866
Provisions 885,571 696,155
Total Current Liabilities 6,793,675 19,381,021
NON-CURRENT LIABILITIES
Provisions 55,869 89,819
Total Non-Current Liabilities 55,869 89,819
TOTAL LIABILITIES 6,849,544 19,470,840
NET ASSETS 143,665,230 101,617,711
EQUITY
Issued capital 297,933,534 237,806,280
Reserves 13,213,671 9,007,355
Accumulated losses (167,481,975) (145,195,924)
TOTAL EQUITY 143,665,230 101,617,711
31 Dec 2016 31 Dec 2015
Accumulated Losses AU$ AU$
Balance at beginning of financial year (145,195,924) (126,187,002)
-
Transfer from convertible notes reserve 671,496
Net loss (22,286,051) (19,680,418)
Balance at end of financial year (167,481,975) (145,195,924)
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66

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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 2016|31 Dec 2015|
|AU$|AU$|
|Cash and cash equivalents|45,911,456|49,322,737|
|Cash and cash equivalents held in joint operations|1,066,723|11,348,160|
|46,978,179|60,670,897|

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(b) Financing facilities

The Group had no external borrowings at 31 December 2016. 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 2016.

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

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||||
|---|---|---|
|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|Loss for the year|(21,759,974)|(19,620,114)|
|Depreciation and amortisation of non-current assets|82,926|44,327|
|Unrealised Foreign exchange gain|(786,641)|(1,329,412)|
|Equity settled share-based payments|2,490,223|1,110,667|
|Interest income|(165,777)|(287,088)|
|(Increase) / decrease in assets:|
|Trade and other receivables|308,231|(183,138)|
|-|
|Other financial assets|(21,329)|
|Other current assets|-|(54,697)|
|Increase / (decrease) in liabilities:|
|Trade and other payables|(1,097,983)|1,054,801|
|Provisions|155,466|167,197|
|Net cash used in operating activities|(20,773,529)|(19,118,786)|

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2016 FAR Annual Report 67

For the financial year ended 31 December 2016

NOTES TO THE FINANCIAL STATEMENTS

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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 2016 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, co-ordinates 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 2016|31 Dec 2015|
|AU$|AU$|
|Financial assets|
|Cash and cash equivalents|46,978,179|60,670,897|
|Trade and other receivables – current and non-current|2,575,664|1,673,542|
|Other financial assets – current and non-current|120,299|116,007|
|Total Financial assets|49,674,142|62,460,446|
|Financial liabilities|
|Trade and other payables|5,928,709|18,761,407|

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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 $3,620,855.

(e) Commodity price risk management

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

(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.

68

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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
2016 % AU$ AU$ AU$ AU$ AU$ AU$
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
2015
Financial assets:
- - - - -
Non-interest bearing 60,735,308 60,735,308
Variable interest rate 2.86% 110,116 - - - - 110,116
Fixed interest rate 2.32% 1,500,000 115,022 - - - 1,615,022
- - -
62,345,424 115,022 62,460,446
Financial liabilities:
- - -
Non-interest bearing 18,628,484 100,714 32,209 18,761,407
- -
18,628,484 100,714 32,209 18,761,407
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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 $16,578.

(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 (2015: net fair value).

2016 FAR Annual Report 69

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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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 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.

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

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|||||||
|---|---|---|---|---|---|
|2015|2013|2012|2012|2012|
|Series 11|Series 10|Series 9|Series 8|Series 7|
|Grant date|01-Jul-15|21-May-13|21-Aug-12|23-Jul-12|31-May-12|
|Share price at grant date|8.7 cents|2.9 cents|4.4 cents|4.9 cents|3.8 cents|
|Fair value|4.9 cents|1.6 cents|2.5 cents|2.9 cents|2.1 cents|
|Expiry date|01-Jun-18|27-May-16|30-Jun-15|23-Jul-15|30-Jun-15|
|Exercise price|10.0 cents|4.4 cents|6.0 cents|6.0 cents|6.0 cents|
|Vesting conditions|(i)|n/a|n/a|n/a|n/a|
|Number of options|
|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|-|8.8 cents|-|-|-|
|Balance as at 1 Jan 2015|68,000,000|62,000,000|6,000,000|10,000,000|50,500,000|
|-|-|-|-|
|Granted during the year|
|-|-|-|-|
|Forfeited during the year|
|-|-|
|Exercised during the year|(6,000,000)|(10,000,000)|(50,500,000)|
|Balance at 31 December 2015|68,000,000|62,000,000|-|-|-|
|Avg. share price at date of exercise|-|-|7.9 cents|8.0 cents|8.0 cents|

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

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|||||||
|---|---|---|---|---|---|
|2015|2013|2012|2012|2012|
|Series 11|Series 10|Series 9|Series 8|Series 7|
|Volatility|95%|97%|100%|100%|100%|
|-|-|-|-|-|
|Dividend yield|
|Risk free interest rate|2.00%|2.57%|3.50%|3.50%|3.75%|
|Option life|2.9 years|3 years|2.9 years|3.0 years|3.1 years|

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(i) The options 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 Senegal joint operation Operator was met.

70

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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 full-time 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:

The following share-based payment arrangements were in existence during the current and prior reportng periods:
2016
Grant date 20-May-16
Share price at grant date 8.7 cents
Fair value 5.5 cents
Expiry date 31-Jan-21
Exercise price A$0.0
Number of optons
Balance as at 1 Jan 2016 -
Granted during the year 21,425,000
Forfeited during the year -
Exercised during the year -
Balance at 31 December 2016 21,425,000
Avg. share price at date of exercise

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:
2016 Volatlity 60%
Dividend yield -
Risk free interest rate 1.63%
Opton life 2.7 years

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

Absolute Total Shareholder Return (‘TSR’)

50% of the Performance Rights will be subject to an absolute total shareholder return hurdle over the Performance Period 31 January 2019 and will be tested at 31 January 2019 (Test 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 2016 at $0.078 per Share, which is the 20 day volume weighted average price (VWAP) preceding 1 February 2016.

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 2019 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-rate 25%-50% Performances Rights granted will vest.

• At 50th percentile, 25% performance rights granted will vest.

• Below 50th percentile, no performance rights will vest.

• 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.

2016 FAR Annual Report 71

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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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 2016|31 Dec 2015|
|AU$|AU$|
|Short-term employee benefits|2,394,291|2,313,208|
|Post-employment benefits|131,507|126,800|
|Share-based payment|1,715,046|767,668|
|Other long-term benefits|59,074|23,955|
|Total|4,299,918|3,231,631|

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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 21 January 2017, FAR commenced drilling the SNE-5 appraisal well and on 8 March 2017 FAR announced SNE-5 was completed 21 days ahead of schedule and significantly below budget. The oil column thickness in SNE-5 was confirmed at 100m gross, as seen at all other SNE oil field wells to date, and it also confirmed reservoir quality and correlation of the principal reservoir units. Overall, SNE-5 flow rates were in line with, or exceeded, pre-drill expectations and a previously untested reservoir section was better than expected:

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.

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.

Prior to SNE-5 being plugged and abandoned, pressure gauges were installed over the tested reservoir units in preparation for the planned SNE-6 appraisal well and completion of an interference test. Prior to drilling SNE-6, the Senegal joint venture elected to drill the VR-1 well, located within the SNE oil field approximately 5 km to the west of the SNE-1 discovery. The VR-1 well is being drilled to is to assess the potential for additional lower reservoir within the western part of the SNE field. In addition, the well will examine deeper Aptian carbonate exploration targets under the SNE field (reference ASX announcement 8 March 2017). Mobilisation of the drill ship to the VR-1 location commenced on completion of SNE-5 operations and the VR-1 well spudded on 9 March.

On 7 February 2017, FAR announced an updated Independent Resources Report for FAR on the exploration potential of the Rufisque, Sangomar and Sangomar Deep (RSSD) blocks, offshore Senegal has been completed by RISC Operations Pty Ltd (“RISC”). This report has highlighted 1,563 mmbbls of prospective resources, of which 234 mmbbls are net to FAR who is a 15% participant in joint venture. In addition to the undrilled prospects, the 2C recoverable resource in the SNE discovery is 641 mmbbls with 96 mmbbls net to FAR (reference ASX announcement 23 August 2016).

There are no further matters or circumstances occurring subsequent to the end of the financial year that have significantly affected, or may significantly affect, the operations of the consolidated entity, the results of those operations, or the state of affairs of the consolidated entity in future financial years.

72

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26. REMUNERATION OF AUDITORS

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||||
|---|---|---|
|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|Auditor of the Parent Entity:|
|Audit or review of the financial report|70,700|67,980|
|-|-|
|Taxation services|
|70,700|67,980|

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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 2016|31 Dec 2015|
|AU$|AU$|
|Assets|
|Current assets|48,845,228|62,230,039|
|Non-current assets|101,669,550|58,858,514|
|Total Assets|150,514,778|121,088,553|
|Liabilities|
|Current liabilities|6,793,675|19,381,021|
|Non-current liabilities|55,869|89,819|
|Total Liabilities|6,849,544|19,470,840|
|Equity|
|Issued Capital|297,933,534|237,806,280|
|Reserves|
|– Option reserve and equity component on convertible notes|8,445,445|5,955,222|
|– Foreign currency translation reserve|4,768,226|3,052,132|
|Accumulated losses|(167,481,971)|(145,195,921)|
|Total Equity|143,665,234|101,617,713|

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(b) Financial performance

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||||
|---|---|---|
|Year ended|Year ended|
|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|Loss for the year|(22,286,050)|(19,680,417)|
|-|
|Transfer from convertible notes reserve|671,496|
|Other comprehensive income/loss|1,716,094|3,453,707|
|Total comprehensive loss|(20,569,956)|(15,555,214)|

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2016 FAR Annual Report 73

NOTES TO THE FINANCIAL STATEMENTS

For the financial year ended 31 December 2016

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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 guarantee entered into by the Parent Entity in relation to the debts of its subsidiaries is 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 (2015: $nil).

(d) Contingent liabilities of the parent entity

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||||
|---|---|---|
|31 Dec 2016|31 Dec 2015|
|AU$|AU$|
|Contingent liabilities|
|Guinea-Bissau – contingent payment from future production|17,965,727|17,793,594|
|Guinea-Bissau – contingent withholding tax liability|784,704|777,185|
|18,750,431|18,570,779|

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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 2016|31 Dec 2015|
|AU$|AU$|
|Exploration and evaluation assets|
|Not longer than 1 year|30,990,005|36,792,291|
|-|
|Longer than 1 year and not longer than 5 years|44,196,263|
|30,990,005|80,988,554|

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Refer to Note 16 for further details.

74

SUPPLEMENTARY INFORMATION

Pursuant to the Listing requirements of the Australian Securities Exchange

Unlisted Options

At 17 March 2017, there were 68,000,000 unlisted options, with a 10 cent exercise price and 1 June 2018 expiry date, held by 11 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.

Number of holders of equity securities

Ordinary Shares

At 17 March 2017, the issued capital comprised of 4,461,532,458 ordinary shares held by 11,004 holders.

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Unlisted Performance Rights

At 17 March 2017, there were 21,425,000 unlisted Performance Rights, with a $nil exercise price and expiry date of 31 January 2021, held by 11 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.

Spread details as at 17 March 2017 – Ordinary Shares

Spread details as at 17 March 2017 – Ordinary Shares
Number of Holders	Number of Units % of Total Issued Capital
1 - 1,000 610	248,605 0.01
1,001 - 5,000 524	1,712,155 0.04
5,001 - 10,000 900	7,483,832 0.17
10,001 - 100,000 5,400	241,780,039 5.42
100,001 and over 3,570	4,210,307,827 94.37
Total 11,004	4,461,532,458 100.00
Holding less than a marketable parcel 1,339

Substantial Shareholder

Substantal Shareholder
Number of shares Percentage
Farjoy Pty Ltd 451,963,236 10.13
Top Twenty Shareholders as at 17 March 2017 Number of shares Percentage
Farjoy Pty Ltd 451,963,236 10.13
J P Morgan Nominees Australia Limited 394,329,109 8.84
HSBC Custody Nominees (Australia) Limited 326,513,675 7.32
Citcorp Nominees Pty Limited 200,073,050 4.48
BNP Paribas Noms Pty Ltd 164,443,620 3.69
Mr Oliver Lennox-King 75,647,869 1.70
Toad Facilites Pty Ltd 67,528,589 1.51
Natonal Nominees Limited 59,208,183 1.33
Mr Rex Seager Harbour 42,744,474 0.96
Fountain Oaks Pty Ltd 34,200,366 0.77
Floteck Consultants Limited 28,000,000 0.63
Mr Benedict Clube 22,000,000 0.49
Mr John Daniel Powell 20,046,777 0.45
N & P Superannuaton Pty Ltd 18,988,839 0.43
Ms Catherine Norman 18,065,883 0.40
Kalan Seven Pty Ltd 17,300,000 0.39
RC Capital Investments Pty Ltd 17,233,760 0.39
Almeranka Superannuaton Pty Ltd 15,605,821 0.35
RBC Investor Services Australia Nominees Pty Ltd 15,355,674 0.34
Knox Enterprises Internatonal Pty Ltd 15,000,000 0.34
2,004,248,925 44.94

2016 FAR Annual Report 75

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CORPORATE DIRECTORY
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DIRECTORS

Nicholas Limb (Chairman) Catherine Norman (Managing Director) Benedict Clube (Executive Director) Albert Brindal (Non-Executive Director) Reginald Nelson (Non-Executive Director)

COMPANY SECRETARY

Peter Thiessen

SHARE REGISTRY

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

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

STOCK EXCHANGE LISTINGS

Australian Securities Exchange ASX Code: FAR

BANKERS

Westpac Banking Corporation 360 Collins Street Melbourne Victoria 3000 Australia

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

SOLICITORS

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

ADR DEPOSITARY

REGISTERED OFFICE & PRINCIPAL PLACE OF BUSINESS

Level 17, 530 Collins Street Melbourne Victoria 3000 Australia

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

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

Website: www.far.com.au Email: info@far.com.au

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76

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