FAR LIMITED - Annual Report 2015 | FinancialReports.eu

22 March 2016

Australian Securities Exchange Level 4, North Tower, 525 Collins Street Melbourne VIC 3000

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Amendment - Annual Report to Shareholders

Please find attached the Annual Report incorporating minor edits on pages 8 and 9 in relation to the Senegal prospective resource estimates.

Peter Thiessen Company Secretary

Annual Report 2015

FAR starts evaluating a world class fi eld

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Contents

01 Company Highlights
02 Chairman’s Review
04 Key Senegal acti viti es in 2015
05 Operati ons Review
15 Corporate Governance
16 Directors’ Report
30 Auditor’s Independence Declarati on
31 Independent Auditor’s Report
33 Directors’ Declarati on
34 Consolidated Statement of Profi t or Loss and Other Comprehensive Income
35 Consolidated Statement of Financial Positi on
36 Consolidated Statement of Changes in Equity
37 Consolidated Statement of Cash Flows
38 Notes to the Financial Statements
65 Supplementary Informati on
66 Corporate Directory

A close look at FAR

Offshore Senegal 3 well Prospective resources Senegal drill SNE FIELD program begins 34 remains the The Ocean Rig Athena world’s largest selected to undertake billion barrels of oil oil discovery by the drilling (approximate total) size since 2014

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From IHS’s (industry
leader in the analysis
of global oil & gas
data) top 10 list of
global discoveries
2014 and 2015
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End of year cash position

End of year cash position 2015 capital raising A$60.7M A$40M with no debt successfully raised through a placement and entitlement offer

FAR outperformed the S&P ASX 200 Energy Index and the Brent oil price over 2015

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0.12
0.11
Ocean rig Athena
0.10 contracted for 3 firm wells
0.09 SNE appraisal
drilling commences
FAR:
0.08
8.3cps -3.5%
0.07
ASX 200 Energy:
0.06 8,010 -31%
Brent oil:
0.05 US$37.28 -35%
0.04
Dec 14 Jan 15 Feb 15 Mar 15 Apr 15 May 15 Jun 15 July 15 Aug 15 Sep 15 Oct 15 Nov 15 Dec 15
FAR S&P ASX 200 Energy Index (rebased) Brent Oil (US$/bbl,rebased)
Source: IRESS, trading data as at 15 Dec 15
FAR market capitalisation (A$m)
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FAR adds low risk follow-on value

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2015 FAR Annual Report 1

Chairman’s Review

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Fellow Shareholders,

Having tasted success in West Africa, we intend to play a key role in progressively unlocking the region...

The old adage, ‘The harder you work, the luckier you get,’ proved true for the FAR team in 2015 with the exploration success of the previous year followed up with very solid appraisal results on the SNE oil discovery early in 2016.

The FAR team, from the board and management to our technical and support staff, have worked extremely hard to create tremendous value for shareholders in the most difficult and challenging market environment in many years.

The support from shareholders for those efforts, by investing when both the share market and world oil prices have been weak, is welcome, encouraging and absolutely necessary if FAR is to capitalise on the great success we have achieved to date.

Significant work still lies ahead.

At year end the SNE-2 appraisal well was in the throes of being completed and the subsequent flow test from SNE-2 proved FAR and its joint venture partners have discovered a world class reservoir containing high quality oil. Further, FAR has confidence that SNE has the necessary attributes to form a commercially viable future development option for our company.

At the time of writing the flow testing of SNE-3 is underway with the third well in the appraisal program, BEL-1 remaining to be drilled. Because of its location, BEL-1 is giving our shareholders the ability to drill a previously undrilled play type on the Senegalese shelf in the Buried Hills play as well as deepening the well to drill into the northern flank of the SNE field. Success in this new play will de-risk a number of similar prospects along the Senegalese shelf.

After BEL-1 the joint venture is considering the drilling of a fourth well and this opportunity has been made possible by the significant savings made in drilling the first three wells by the strong performance Ocean Rig Athena and the drilling management team.

This modern drill ship was four weeks ahead of schedule after the first two wells, potentially providing the opportunity to drill a fourth well within the budget provided for the three planned appraisal wells.

But the appraisal program does not end with the completion of the currently planned wells.

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Tremendous amounts of work are still required to process and interpret the seismic data recently acquired over our offshore Senegalese blocks. Along with the current drill program this will take up much of the current year, as will planning for another round of exploration/appraisal and potentially, development drilling for 2017.

Throughout 2015 work by the FAR technical team, and confirmed by the independent consulting firm RISC, resulted in a significant increase in the oil resources within the SNE field.

‘1C’ contingent resources in the SNE field rose by 60% and ‘2C’ resources climbed by 40%. These very large increases were calculated on the basis of additional knowledge obtained from reprocessing our seismic database following the drilling of the two discovery wells. The fact that these resource upgrades do not include any information or results from the SNE-2, SNE-3 or BEL-1 wells is giving FAR confidence for further upgrades of the SNE resource once all the data is fully assessed.

Having tasted success in West Africa, we intend to play a key role in progressively unlocking the region as we strategically progress our projects offshore Senegal and Guinea-Bissau, regions where FAR has developed specialised and unique intellectual property. Drilling of new plays in Senegal and in the Company’s other West African exploration acreage is under active evaluation.

Offshore Senegal remains largely unexplored and holds enormous potential for discovery of very large oil fields. We are confident, using knowledge we have gained from the work to date, of developing excellent new opportunities for discovery.

During the year, FAR negotiated an option giving us the opportunity to acquire a 75% interest, over the neighbouring Djiffere permit which has added to our exploration footprint in the shelf edge play.

While the key focus is on West Africa other assets in FAR’s extensive portfolio remain under active evaluation.

In Kenya security issues remain a key factor in the pace of exploration. However, in recognition of the security issues the Government of Kenya has awarded the joint venture a one year extension to the current PSC which will allow FAR and its partners to progress exploration in the block.

FAR’s Australian assets are expected to be farmed out as the Company continues to focus on West Africa.

As global oil markets restructure to meet the current supply glut, oil prices will stabilise and begin to strengthen. In the meantime the low oil price environment is providing FAR with the opportunity to drill and otherwise explore at costs not seen for a long time.

This is an advantage which should not be overlooked or traded off against short term views about the Company’s share price. FAR’s share price has performed very strongly in comparison to peer companies.

I wish to thank shareholders for your ongoing support of the board and management team and to express my appreciation to those who have provided encouragement by continuing to invest regardless of the broader market pressures.

FAR has entered the most exciting year in its history and I am proud to be Chairman of a company that has such outstanding staff who have such a strong commitment to building on the success of their own hard work and to creating real value for its shareholders.

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Nic Limb Chairman

We are currently assessing whether the success in Senegal can be repeated further along the continental shelf in Guinea-Bissau.

2015 FAR Annual Report 3

Key Senegal activities in 2015

PSC extended by Joint venture commitment to drill

years starting from 6 February 2016 3

firm wells SNE-2 SNE-3 BEL-1 3

and acquisition of a new 3D seismic survey over the Sangomar and Rufisque Blocks

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Ocean Rig Athena selected to undertake drilling and evaluation program. Drilling commenced early November 2015

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drilled, cored, logged and SNE-2 tested ahead of schedule

flowed a combined bpd of oil 9,000 from testing of two reservoir zones

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SNE contingent resource upgraded

announced upon receipt of Independent Resource Report by RISC

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Acquisition of new Senegal joint venture

km[2] 2,400 3D seismic survey

400 km[2] Djiffere Block 3D seismic survey completed in November 2015

FAR is de-risking Senegal

Djiffere option for FAR to earn

interest in 75% the block

after acquiring new 3D seismic and future commitment to drill an exploration well

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Operations Review

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OFFSHORE WEST AFRICA

Proving deep water elephants offshore Senegal

In West Africa, FAR’s portfolio of exploration permits include offshore Senegal and Guinea-Bissau.

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Far left Aminata Toure, Director General of Ministry of Hydrocarbon, Senegal
Far right: Gogne Seye, Country Manager, Senegal
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Mauritania
Marsouin-1
Tortue-1
Guembeul-1
FAN-1
discovery
Rufisque Senegal
Sangomar Djiffere
Deep Offshore
Sangomar
The Gambia
SNE-1
discovery
Guinea-Bissau
2
4A
5A
0 100 Guinea
km
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FIGURE 1: FAR’s offshore acreage, Senegal and Guinea-Bissau

SENEGAL

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

FAN-1 and SNE-1 were the first exploration wells to be drilled offshore Senegal for over 20 years and the first wells ever to be drilled in water deeper than 500 metres. FAR announced in Q4 2014 that both wells met key pre-drill objectives, and each well delivered a significant world class oil discovery with a potential resource volume to justify a stand-alone oil development project.

Following the highly successful 2014 Senegal drilling campaign, FAR Ltd (‘FAR’) and its joint venture partners ConocoPhillips, Cairn Energy (‘Cairn’) and Petrosen (the Government of Senegal) submitted a three year evaluation work program to the Government of Senegal in early May 2015. This was subsequently approved by a Presidential decree which extends the current Petroleum Sharing Contract (PSC) by the requested three years starting from 6 February 2016. This extension allows the joint venture time to appraise the world class SNE and FAN oil discoveries made in 2014 and to evaluate the considerable exploration potential which remains within the PSC area.

The evaluation work program includes an initial, firm, three well drilling program and a 3D seismic survey. This is expected to be followed by further drilling and geological and engineering studies in order to confirm commerciality of a development project and upon success, leading to the exploitation phase under the PSC.

The firm three well drilling program included two appraisal wells, SNE-2 and SNE-3, designed to progress our understanding of field size and reservoir deliverability with the aim of establishing commerciality as soon as possible. The third well, BEL-1, will be the first exploration well to be drilled in the blocks following the discoveries in the FAN-1 and SNE-1 wells.

2015 FAR Annual Report 5

Operations Review

The BEL-1 well will be drilled into the undrilled Buried Hills play in a prospect named Bellatrix. The BEL-1 well will also be deepened to appraise the northern flank of the SNE field.

A new, 2,400km[2] 3D seismic survey over the Sangomar and Rufisque Blocks was acquired to complement the existing 3D seismic coverage of the prospective acreage in the Senegal PSC contract area. The aim of this program is to identify prospects to the north and the east and update the inventory of drillable prospects. The survey will also assist with the delineation of the existing SNE discovery.

THREE WELL DRILLING PROGRAM

The SNE discovery was ranked by IHS CERA as the world’s largest oil discovery for 2014 and it is the focus of the first phase of the joint venture’s Senegal appraisal drilling program.

Initial analysis of the SNE-1 well data showed:

95 metre gross oil bearing column with a gas cap
Excellent Albian age reservoir sands with net oil pay of 36 metres
High quality oil of 32 degrees API from samples of gas, oil and water recovered to surface
Operator’s preliminary estimates of the gross contingent recoverable resource range from a 1C of 150 mmbbls, 2C, 330 mmbbls to a 3C of 670 mmbbls (net to FAR; 1C: 23 mmbbls, 2C: 50 mmbbls, 3C: 101 mmbbls)[*]

The primary objective of the SNE appraisal program is to prove an economic oil volume to support the future commercial development of the SNE oil field. FAR’s economic analysis has determined the commercial threshold for a SNE standalone development to be >=200 mmbbls (gross).

From further analysis of well and reprocessed seismic data, FAR assessed potential for additional net pay and resources not included in the preliminary assessment of contingent resource estimates for the SNE field. This potential includes thin bed reservoir sands that, recent detailed post well analysis has indicated encouraging reservoir characteristics. FAR’s revised assessment of contingent resources for the SNE discovery was assessed by RISC, and on 8 February 2016 FAR announced

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Senegal
FAN-1 BEL-1
discovery
SNE-2
SNE-1
discovery
SNE-3
0 50
km
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FIGURE 2: Sangomar prospects and leads, offshore Senegal

the completion of an Independent Resources Report by RISC prepared as at December 2015.

The SNE-2 and SNE-3 appraisal wells are the first two wells in the firm three well back-to-back drilling program. They are expected to intersect all potential SNE field reservoir zones and the wells are to be flow tested (drill stem tested) and cored at certain intervals. Both of these wells are expected to provide key data towards proving that SNE exceeds the minimum economic field size.

BEL-1 (Bellatrix) is the third well in the firm drilling program. The Bellatrix exploration prospect will evaluate the undrilled Buried Hills play, which has a strong seismic amplitude response that appears similar in nature to that which proved to be hydrocarbons in SNE. Bellatrix is located above the northern flank of the SNE discovery, so this well has been designed to be deepened so it intersects both the Bellatrix prospect and appraise the northern flank of the SNE field.

OCEAN RIG ATHENA SELECTED

In October 2015, FAR and its Senegal joint venture partners executed contracts for the use of the Ocean Rig Athena drillship for the Senegal drilling program. Ocean Rig Athena is a new, 7th generation, dual derrick, dynamically positioned drill ship (Enhanced SAIPEM10000 design) that was first delivered on 24 March 2014. After successfully completing acceptance testing it commenced drilling operations in Angola in June 2014 under a three-year drilling contract with ConocoPhillips.

The Ocean Rig Athena day rate for the Senegal joint venture has been adjusted downwards to reflect prevailing market conditions, where day rates have dropped by up to 50% for deep water drilling units offshore Africa. These reduced rates are expected to allow the Senegal drilling and testing program to be completed for a heavily reduced cost in comparison to what was envisaged under a much higher previously existing oil price environment.

Ocean Rig Athena drilling activity offshore Senegal commenced in early November with operations initially on the top hole of SNE-3 followed by the drilling of the SNE-2 well to total depth (TD) of approximately 2,770 metres.

The Oil Rig Athena drillship

The SNE-2 well began drilling in the Sangomar Deep Offshore Block on 4 November 2015 and it reached its planned total depth of 2,825 metres total vertical depth on 3 December 2015.

SNE-2 WELL RESULT

On 2 November, FAR announced the commencement of the appraisal drilling program. The top hole section of the SNE-3 well was drilled before the SNE-2 well was spudded on 5 November. On 4 January 2016, FAR announced the results of the successful SNE-2 appraisal well and flow test. The well was safely drilled, cored, logged and tested ahead of schedule and oil flows from the drill stem testing (DST) demonstrated SNE is a world class oil discovery with the ability to flow oil at commercially viable rates:

A drill stem test (DST) of the lower principal oil reservoir unit over a 12 metre interval (~11.5 metre 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 is greater than the testing equipment capacity of 10,000 bopd. This result confirms the high deliverability of the principal SNE reservoir units.
A DST of a shallower ‘heterolithic’ reservoir unit over a 15 metre interval (~3.5 metre 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 ‘heterolithic’ reservoir units to produce at viable rates and make a material contribution to SNE oil resource and production volumes.
SNE-2 appears to have the same high quality 32 degree API oil seen in SNE-1.
Gross oil column thickness at SNE-2 confirmed at 103m gross, showing a similar oil-down-to and oil-up-to depth as seen at SNE-1 of 96m gross.
SNE-2 has confirmed the correlation of the principal reservoir units between SNE-1 and SNE-2 and the potential for lateral reservoir continuity.
A total of 216 metre of continuous core (100% recovery) was recovered across the entire SNE field reservoir interval.

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WEST SNE-2 SNE-1 EAST
Shales
Maastrichtian Shales
Sandstones
Carbonates
TD 2800m
TD 3085m
Depth in mTVDSS Top Aptian Carbonates
Unconformity
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The flow test
demonstrated SNE
is a world class oil
discovery with the
ability to flow oil
at commercially
viable rates.
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At the completion of drilling of the SNE-2 well, FAR announced that the rig had mobilised to re-enter the SNE-3 well with the intention of drilling to total depth before the commencement of a coring, logging and testing program in the well. At the time of writing, the testing program is underway. The Ocean Rig Athena performance has been such that the drilling program to date is well ahead of schedule.

SNE OIL FIELD CONTINGENT RESOURCES UPGRADE

On 8 February 2016, FAR announced that an Independent Resources Report had been completed by RISC for FAR’s SNE oil discovery, offshore Senegal. The report was prepared as at December 2015 incorporating recent data available from wells SNE-1 and FAN-1 and reprocessed 3D seismic.

The SNE contingent resources set out in RISC’s Independent Resource Report represented a material increase to the estimates previously reported by FAR in late 2014 (Refer: FAR ASX announcement 10 November 2014).

SNE oil field contingent resources (100% basis, recoverable) have been upgraded by RISC to 240 million barrels of oil (‘mmbbls’) 1C, 468 mmbbls 2C, 940 mmbbls 3C.
The SNE oil field contingent 2C resource of 468 mmbbls (70 mmbbls net to FAR) represents a 42% increase to the previous estimate of 330 mmbbls (50 mmbbls net to FAR).

FIGURE 3: Cross section schematic showing location of the SNE-1 and SNE-2 wells

2015 FAR Annual Report

Operations Review

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Senegal Resource Estimate
Discoveries Play (mmbbls)
FAN-1 Slope FAN 950 [(i)]
P50 Gross STOIIP
SNE-1 Albian shelf edge 468 [(ii)]
2C Contingent
Prospective
Resources []
Senegal Best Estimate
Exploration Play (mmbbls)
Soleil Albian shelf edge 101
Sirius Albian shelf edge 204
Bellatrix Buried Hill Play 168
Sabar Buried Hill Play 141
Lamb-Ji Buried Hill Play 74
Ramatou Buried Hill Play 77
Alhamdulillah North Salt Anticline Play 140
South Canyon Slope FAN Play 258
Central Canyon Slope FAN Play 338
Total All Prospects 1500
Total Net to FAR 225
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(i) Resource Estimates confirmed by the Operator (ERC Equipose Ltd)

(ii) Resource estimates confirmed by FAR (RISC)

TABLE 1: Prospective and Contingent Resource[*] inventory for FAR’s Senegalese permits

New SNE-2 well data, plus analysis of new 3D seismic and further appraisal activity is expected to lead to future revisions to the SNE field resource estimates.

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Dakar port

SNE OIL FIELD CONTINGENT RESOURCES UPGRADE

SNE oil field contingent resources (100% basis, recoverable) have been upgraded by RISC to 240 million barrels of oil (‘mmbbls’) 1C, 468 mmbbls 2C, 940 mmbbls 3C.
The SNE oil field contingent 2C resource of 468 mmbbls (70 mmbbls net to FAR) represents a 42% increase to the previous estimate of 330 mmbbls (50 mmbbls net to FAR).

New SNE-2 well data, plus analysis of new 3D seismic and further appraisal activity is expected to lead to future revisions to the SNE field resource estimates.

DJIFFERE BLOCK OPTION

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. The estimates exclude the SNE and FAN oil discoveries.

The western part of the Djiffere Block is located along geological trend with the shelf play types identified in the eastern part of FAR’s RSSD Blocks. FAR has identified a number of potential shelf structures within the Djiffere Block from existing 2D seismic data, with one lead already estimated by FAR to have potential to contain in excess 100 million barrels of unrisked prospective resources. The Djiffere Block, being in shallow water, is suitable for low cost drilling and near term development projects.

Under its 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 (subject to Government approvals). The farm-in option can be exercised by FAR at any time before 31 October 2016, by which time FAR expects to have completed the firm 3 well shelf drilling program in its RSSD blocks.

3D SEISMIC SURVEYS

The Polarcus Adira vessel began the new Senegal joint venture 3D seismic survey over FAR’s Sangomar and Rufisque Blocks in September 2015. This 3D survey has been designed to acquire data in the north and east parts of the permits along trend from existing mapped prospects where there is currently no 3D seismic data coverage.

FAR also awarded Polarcus a contract to undertake a 3D seismic survey in the western part of the Djiffere Block. This survey will provide 400km[2] of new 3D coverage to evaluate the shelf trend potential within the Djiffere Block. The Djiffere seismic survey was shot as an extension of the Sangomar and Rufisque 3D seismic survey that was conducted by the Senegal joint venture partners.

Both 3D seismic surveys were completed efficiently in November 2015 and final processed products are expected from Q4 2016.

The Polarcus Adira vessel began the new Senegal joint venture 3D seismic survey over FAR’s Sangomar and Rufisque Blocks in September 2015.

EXPLORATION POTENTIAL

The FAN-1 and SNE-1 oil discoveries have provided FAR with encouragement that further exploration drilling will result in more discoveries offshore Senegal. FAR’s corporate strategy is therefore to focus on its core asset base offshore Senegal and mature its prospect inventory with an initial focus on the shelf area.

Having proven the existence of the working source rock, the prolific nature of the source rock and the oil migration pathways to filling the traps, the geological chance of success for finding oil in all the prospects located in FAR’s acreage offshore Senegal has been significantly upgraded.

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Oil Dakar
Gas Senegal
Shelf Play
Buried Hills Play
Fan Play
4WDC Salt Play
Sangomar 3D Seismic Rufisque
2015 3D seismic
Djiffere 3D Seismic
Rufisque Dome wells
Sangomar
Deep FAN-1 Djiffere
Sangomar
BEL-1
SNE-2
SNE-1
SNE-3
0 20
km
50 m
ProspectiveShelf Trend
1000 m
100 m
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FAR has mapped a total gross, unrisked best estimate of prospective resources of 1,500 mmbbls[] with 225 mmbbls[] net to FAR in several prospects that lie within subsea tie-back distance to a proposed SNE production hub. The estimates exclude the SNE and FAN oil discoveries.

The evaluation of this significant contingent and prospective resource inventory began with the new Senegal drilling and testing program (SNE-2, SNE-3 and BEL-1) that started late 2015. FAR also expects to re-evaluate its prospect inventory following the receipt of the re-processed 3D seismic data and new 3D seismic surveys undertaken over 2015.

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Oil
Gas
Shelf Play
Buried Hills Play
Fan Play
4WDC Salt Play
3D Survey
Ramatou
Lamb-ji
Sabar
BEL-1
0 10
km
Rufisque
Shelf edge
Sirius
Sangomar
Sangomar
Deep
Bellatrix
Central Fans
Southern Fans
Alhamdulillah North
FAN-1
SNE-2
SNE-1
SNE-3
Soleil
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FIGURE 4: Location of the new seismic surveys

FIGURE 5: prospects as defined by the 3D seismic data

2015 FAR Annual Report 9

Operations Review

GUINEA-BISSAU

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

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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 6: FAR licences offshore Guinea-Bissau

In late April 2015, the Government of Guinea-Bissau approved a 3 year extension to the current exploration term. The extension period began on 26 November 2015.

The joint venture has approved a work program including the drilling of one appraisal well on the Sinapa West oil discovery at the end of 2015. However, in light of FAR’s neighbouring discovery on the shelf offshore Senegal (SNE-1), a re-interpretation of the Guinea-Bissau 3D seismic data is ongoing to assess the potential for this oil play in the blocks.

The joint venture has acquired additional 3D seismic over the shelf edge to image prospects identified in this region that are potentially analogous to the SNE discovery, offshore Senegal. This new 3D data has been specifically designed to evaluate the large Atum prospect which was previously only partially covered by 3D data.

The new seismic data is being processed and was delivered in Q4 2015.

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Social Responsibility in Guinea-Bissau – providing essential funds for mosquito nets in local villages.

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Salt dome
1
Prospect/lead
3D Seismic Survey 2012
3D Seismic Survey 2014
2
West Sinapa
Atum Sabayon
East Sinapa
Arinca
North Solha
4A
4B
5A
6A
5B
0 20
6B km
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FIGURE 7: Block 2 and Blocks 4A/5A prospects, offshore Guinea-Bissau

Contingent & Prospective Resources[*]

	Contngent & Prospectve Resources*
Guinea-Bissau Prospect	Low Estmate (mmbbls) Best Estmate (mmbbls) High Estmate (mmbbls)
Sinapa Discovery Contingent Resources	4.4 13.4 38.9
Total Contingent Resources	4.4 13.4 38.9
Total Net to FAR Contingent Resources	0.7 2 5.8
East Sinapa Prospective Resources	1.8 7.5 34.2
West Sinapa Prospective Resources	17.7 64.7 251.7
Atum Prospective Resources	144 471.7 1,569.6
North Solha Prospective Resources	6 28.4 131.6

Arinca Prospective Resources	10 59.2 393
Sabayon Prospective Resources	3.4 18.1 88.2
Other leads Prospective Resources	85.4 303.7 1,032
Total All Prospects	269 954 3,500
Total Net to FAR	40 143 525

TABLE 2: FAR’s Contingent and Prospective Resources[*] offshore Guinea-Bissau

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EAST AFRICA

Large equity positions in a fast emerging oil and gas margin

FAR has an interest in two Kenya permits: Block L6 and Block L9. These blocks are 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 recent oil discovery in the Sunbird-1 well offshore Kenya. A map showing the location of FAR’s two blocks offshore Kenya is given in Figure 8.

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Kenya
L6
L9
0 100
km
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FIGURE 8: FAR’s two blocks offshore Kenya

KENYA: Lamu Blocks

Block L6

Onshore – 24% paying and beneficial interest[ (i) ] 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 400 metres.

In February 2014, FAR executed a farm-out to the Milio group of companies. Pursuant to the terms of the farm-out agreement FAR is fully carried through a proposed onshore well and an onshore 2D seismic survey and associated processing and interpretation. The farm out agreement with Milio and the associated carried work program relate to the onshore portion of Block L6 only where FAR has retained a 24% free carried interest. Any onshore gas discovery in Block L6 provides near term potential for gas to be sold for domestic power generation.

Since executing the farm-out agreement, the agreed onshore work program, to be operated 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 venture a 12 month extension.

FAR has been working with Milio and the Kenyan Ministry of Energy and Petroleum to monitor the local security situation in and around the onshore portion of Block L6 and put in place appropriate risk mitigation strategies to ensure appropriate access for petroleum operations is established. As at the reporting period the conditions precedent to the farm out agreement have not been completed and the parties were negotiating an amendment to the farm out agreement in light of the implications of the above mentioned circumstances See Note 18(ii) for further details.

(i) Subject to completion of Milio farm-out agreement. Current paying beneficial interest is 60%

2015 FAR Annual Report 11

Operations Review

In relation to the offshore portion of Block L6 where FAR has a 60% interest, FAR has been progressing a farm-out initiative for drilling an offshore well. The recent Sunbird-1 oil discovery in the nearby Kenya Block L10A targeted a Miocene reef structure. The Miocene reef play extends along the coast of Kenya and through both of FAR’s offshore Blocks, L6 and L9. The discovery of oil in the Sunbird-1 well at the southern extent of the Miocene reef play and evidence for oil in the Maridadi well, drilled at the northern extent in L6, has generated strong industry interest in FAR’s Block L6 farm-out.

In 2012, FAR completed a 778km² 3D seismic survey over the L6 permit offshore Kenya. The survey was conducted by Fugro Geoteam and was completed within the approved budget and expected schedule. Combined with existing 2D mapping, FAR has identified a number of hydrocarbon play types and prospects. Within the additional 3D coverage, FAR has matured three prospects (Tembo, Kifaru and Kifaru West) which have prospective resources of 327, 178 and 130 million barrels of oil (un-risked best estimate, 100% basis) respectively, or in a gas only success case, 807, 517 and 388 billion cubic feet of gas. The chances of a discovery of the three prospects have been assessed to be 21%, 19% and 18% respectively.

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 (un-risked, best estimate, 100% basis).

Block L9

30% paying and beneficial interest

Operator: Ophir Energy PLC (‘‘Ophir Energy’)

The assignment agreement between FAR and Ophir Energy (the Operator of Block L9) expired on 23 July 2014. Following this date, FAR and Ophir Energy have held discussions regarding FAR’s entry into the block FAR is currentl ~~y s~~ eeking to resolve the status of its interest.

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Miocene Reefs
Miocene Fans
Eocene Clastics
Cretaceous Clastics
Other leads
& prospects
Gas discovery L6
Oil & Gas discovery Kubwa-1
Eocene Oil Kitchen
Kenya
Mbawa
Discovery
L9
Sunbird
Discovery Kiboko-1
0 50
Pemba Island km
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FIGURE 9: Leads and prospects mapped offshore Kenya

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Prospective
Resources []
Kenya L6 Best Estimate
Prospects Play (mmbbls)
OFFSHORE
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 95
Clastics Play
Total 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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TABLE 3: Estimate of Prospective Resources[*] for Block L6, Kenya

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AUSTRALIA

Surrounded by proven petroleum systems

Hydrocarbon exploration in the Dampier Sub-basin dates back to the late 1960s when Legendre-1 encountered oil. Since then, over 200 exploration and development wells have been drilled with an exploration technical success rate of 41%. Commercial success rates are >20%. Historically, the exploration focus has been on structural traps, with wells concentrated along the basin margins and along prominent inversion trends. More recently, exploration has begun to test the stratigraphic trapping potential closer to the main depositional-centres where turbidite sands are more concentrated.

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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 10: Location of Blocks WA-457-P and WA-458-P, offshore Western Australia

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 has participated in a speculative 3D seismic survey acquired over 62% of the WA-458-P permit that commenced in Q2 2015. Final processed products from the survey are expected to be delivered at the end of Q2 2016. Data acquisition was restricted over the Glomar Shoals in the permit and complete coverage is expected to be made in 2016.

Following the success of FAR’s Senegal program, FAR intends to farm-down its high interest in these permits to focus on delivering shareholder value through continued work in Senegal.

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

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

2015 FAR Annual Report 13

Operations Review

CORPORATE ACTIVITY

At the end of the financial year FAR had a robust cash position with combined cash and long term deposits of AU$60.7 million and no debt. In November 2015, FAR successfully raised approximately AU$40 million through a placement of fully paid ordinary shares to investors and a pro-rata non-renounceable entitlement offer of fully paid ordinary shares in FAR to existing eligible shareholders. The placement raised approximately AU$25 million, and the 1 for 17 underwritten pro-rata non-renounceable entitlement offer raised approximately AU$15 million. The proceeds from the placement and entitlement offer (after costs) are being used in support of FAR’s capital expenditure in Senegal, including the two appraisal wells on the SNE oil discovery (SNE-2 and SNE-3) and the shelf exploration well (BEL-1).

EXPLORATION ASSETS

FAR holds a wide portfolio of exploration licences across 10 blocks 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 began a 3 well firm drilling program offshore Senegal in late 2015 that initially focuses on appraising the world class SNE discovery at SNE-2 and SNE-3, and it will also evaluate the Buried Hills exploration play and the northern extent of the SNE field at BEL-1. FAR has also entered into an option agreement to earn a 75% working interest in the Djiffere Block, located adjacent to FAR’s highly prospective Rufisque, Sangomar and Sangomar Deep (RSSD) Blocks that contain the significant SNE-1 and FAN-1 oil discoveries. Guinea-Bissau and Kenya represent FAR’s other African assets. As at the end of 2015, the Company assets are tabled below.

Project	1 Terms of FAR’s Optons over the Djifere Block. The farm-in opton can be exercised by FAR at any tme before 31 October 2016. 2 Subject to the completon of the farm-out agreement with Milio. Current paying and benefcial interest is 60% 3 The agreement with Ophir Energy terminated during the 2014 year and discussions have been ongoing to resolve FAR’s equity transfer. Asset FAR Paying Interest Benefcial Interest Operator Rufsque, Sangomar and Sangomar Deep 16.7% 15.0% Cairn Energy Djifere 82.5%1 75%1 FAR Block L6 (ofshore) 60% 60% FAR Block L6 (onshore) 24%2 24%2 FAR Block L9 30%3 30%3 Ophir Block 2, 4A, 5A 21.43% 15.0% Svenska WA-458-P 100% 100% FAR WA-457-P 100% 100% FAR
Senegal

Kenya
Guinea-Bissau
Australia

*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 prospective resource estimates presented in this report are prepared as at 27/2/2013, 11/3/2014, 5/2/2014 and 13/04/2015. (reference: FAR ASX releases of 27/02/2013, 11/3/2014, 5/2/2014 and 13/04/2015) . 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. Unless otherwise stated the 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 prospective resource estimates include Government share of production applicable under the Production Sharing Contract.

Competent Person Statement Information – In this report information relating to hydrocarbon resource estimates has been compiled by Peter Nicholls, the FAR Ltd 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 Prospective Resources in the form and context in which it appears.

Forward looking statements – This report 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 report, the words such as ‘could’, ‘plan’, ‘estimate’, ‘expect’, ‘intend’, ‘may’, ‘potential’, ‘should’ and similar expressions are forward looking statements. Although FAR 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 Report and that all material assumptions and technical parameters underpinning this Report continue to apply and have not materially changed.

*Notes to Prospective Resources Estimates

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.
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.
The Prospective resource estimates have been estimated using deterministic methods using best estimates of all parameters.
The barrel of oil equivalent (BOE) is a unit of energy based on the approximate energy released by burning one barrel (42 U.S. gallons or 158.9873 litres) of crude. One BOE is roughly equivalent to 5,800 cubic feet (164 cubic meters) of typical natural gas, which is the conversion used in this analysis to calculate BOE for the gas volumes. The value is necessarily approximate as various grades of oil and gas have slightly different heating values.
The Best Estimates reported represent that there is a 50% probability that the actual resource volume will be in excess of the amounts reported.
The estimates for unrisked Prospective Resources have not been adjusted for both an associated chance of discovery and a chance of development.
The chance of development is the chance that once discovered, an accumulation will be commercially developed.
Prospective Resources means those quantities of petroleum which are estimated, as of a given date to be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective resources have both an associated chance of discovery and a chance of development.
In the table, the abbreviation ‘mmbbls’ means millions of barrels of oil or condensate and ‘bcf’ means billions of cubic feet of gas.

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

Policies

Anti-Bribery & Corruption

Code of Conduct

Diversity

Environment & Sustainability Human Rights & Child Protection Market Disclosure & Communications Risk Oversight & Management Security Trading & Policy Statement

This year FAR has published its Corporate Governance Statement on its website rather than in its annual report. Our 2015 Corporate Governance Statement can be viewed on our website at www.far.com.au/governance-social -responsibility/.

2015 FAR Annual Report 15

Directors’ Report

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The directors of FAR Ltd submit herewith the Annual Financial Report for the year ended 31 December 2015. 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 Executive Chairman of Mineral Deposits Limited, an Australian listed company and Non-Executive Chairman of World Titanium Resources Limited. Mr Limb was appointed as a Director of the Company on 28 November 2011, and appointed Chair on 19 April 2012. He is also a member of the nomination committee, remuneration committee and audit committee.

Catherine Margaret Norman – Managing Director

Bsc (Geophysics) (appointed 28 November 2011)

Ms Norman is a professional geophysicist who has over 25 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 20 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. Mr Clube holds a Bachelor of Science (Honours) degree in Geology from the University of Edinburgh and is an associate of the Institute of Chartered Accountants of England and Wales, a member of the Australian Institute of Company Directors and a member of the Association of International Petroleum Negotiators.

Charles Lee Cavness – Non-Executive Director (resigned 15 May 2015)

Mr Cavness resides in Denver, United States of America, and is an Attorney at Law admitted to practice before the Supreme Courts of the United States and of the States of Texas, Alaska, and Colorado. Mr Cavness served in the legal departments of two large American oil companies – Pennzoil Corporation and Arco. Mr Cavness has spent his entire career in the oil industry, and consequently has experience in North and Latin America,

Europe and the Middle East. Mr Cavness has been a director of the Company since 1994 and is also a member of the nomination committee, remuneration committee and audit committee.

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 2000 until 4 April 2013. He is also a member of the nomination committee, remuneration committee and audit committee

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 45 years of experience in the petroleum and minerals industries and has served as a Councillor of the Australian Petroleum Production and Exploration Association. He was Managing Director of Beach Energy for 13 years plus 10 years as CEO and Executive Director. He is the recipient of the APPEA’s Reg Sprigg Gold Medal in 2009 for outstanding services to the Australian oil and gas industry. Mr Nelson is a member of the nomination committee, remuneration committee and audit committee

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
Mr N J Limb	Mineral Deposits	Since 1994
	Limited World Titanium	Since 25 October
	Resources Limited	2013
Mr B J M Clube	Oilex Ltd	2009-2012

DIRECTORS’ SHAREHOLDINGS

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

Fully Paid Ordinary	Optons Over
Shares	Ordinary Shares
N J Limb 34,908,139	5,000,000
C M Norman 4,674,090	24,000,000
B J M Clube 11,732,000	20,000,000
R G Nelson 500,000	5,000,000
A E Brindal 350,955	-

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 GRANTED TO DIRECTORS AND SENIOR MANAGEMENT

During and since the end of the financial year an aggregate of 47,000,000 options were granted to the following directors and the 3 highest paid officers of the company as part of their remuneration:

Directors & senior	Number	Issuing	Number of
management	of optons	entty	ordinary
	granted		shares under
			opton
R G Nelson	5,000,000	FAR Ltd	5,000,000
C M Norman	10,000,000	FAR Ltd	10,000,000
B J M Clube	8,000,000	FAR Ltd	8,000,000
P J Nicholls	8,000,000	FAR Ltd	8,000,000
G A Ramsay	8,000,000	FAR Ltd	8,000,000
P A Thiessen	8,000,000	FAR Ltd	8,000,000

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.

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 2015 after income tax was $19,620,114 (2014: $6,937,168).

DIVIDENDS

The directors recommend that no dividend be paid for the year ended 31 December 2015 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

	FY15 $ FY14 $ Change %
Proft & loss
Revenue	287,088 629,293 (54%)
Expenses	(19,907,202) (8,255,083) 141%
Loss for the period	(19,620,114) (6,937,168) 183%
Basic EPS (cents)	(0.57) (0.26) 119%
Financial positon
Net assets	102,288,270 75,288,170 36%
Cash balance	60,670,897 67,225,297 (10%)
Cash fows
Operatng cash fow	(19,118,786) (11,306,178) 69%
Investng cash fow	(31,958,434) (263,845) 12013%
Financing cash fow	42,036,017 52,385,675 (20%)

2015 FAR Annual Report 17

Directors’ Report

The group reported loss for the 2015 year of $19,620,114 is 183% greater than the prior year loss of $6,937,168 due mainly to higher exploration expenses. Senegal exploration costs increased by $8,898,444 in the 2015 year to $12,611,392 due to increased activity. Included in these costs are 3D seismic acquisition for both the Sangomar and Djiffere Blocks and additional geoscience and engineering works as part of the assessment of the 2014 offshore discoveries as well as planning for the 2015 appraisal and exploration wells. Higher exploration costs were also incurred during the year in Australia and Guinea-Bissau which included the acquisition of 3D seismic for both projects. Revenue representing interest income decreased by 54% to $287,088 in 2015 as the majority of the funds held on term deposit were converted to USD from AUD. This hedged the Company against future project funding costs for Senegal, Guinea-Bissau and Kenya which are all funded in USD.

Financial position

The Group’s balance sheet was strengthened during the year by the $40,027,333 capital raising before costs which included a placement in October of $25,000,000 and the 1 for 17 non renounceable rights issue in November of $15,027,333. A further $3,990,000 before costs was raised via the exercise of 66.5 million employee options during the year.

Net assets increased by 36% to $102,288,270 from the prior year of $75,288,170. The net increase of $27,000,100 reflects the increase in issued capital of $42,036,017 plus the increase in reserves of $3,912,701 less the operating loss for the year of $19,620,114. The increase in issued capital and the operating loss are explained above, the increase in reserves includes an increase in the foreign currency translation reserve of $3,473,530 and the option reserve of $1,110,667. The increase in the foreign currency translation reserve reflects the net increase in value of the joint operation assets held in USD due to the strengthening of the USD against the AUD during the year. The option reserve increase represents the current year cost of the 68 million employee options issued in July 2015.

Total assets for the 12 months to 31 December 2015 increased by $17,400,010 reflecting a decrease in current assets of $7,529,105 an increase in non-current assets of $24,929,115.

The decrease in current assets is mostly explained by the decrease in cash and cash equivalents of $6,554,400 to $60,670,897. The decrease reflects the $19,118,786 operating cash outflows and investing outflows of $31,958,434 mostly relating to payments for exploration expenses and exploration capitalised in relation to the 2014 and 2015 Senegal joint operation exploration and appraisal offshore well programs offset by the net proceeds from the issue of shares of $42,036,017 and the effect of exchange rate differences on cash and cash equivalents of $2,486,803.

The increase in non-current assets is due predominantly to the $24,736,339 increase in exploration and evaluation assets. These costs relate to the capitalisation of the Senegal joint operation SNE-2, SNE-3 and BEL-1 offshore appraisal and exploration well costs.

Total liabilities decreased during the year by $9,600,090 to $19,547,381 due mainly to the decrease in trade and other payables from $28,528,694 to $18,761,407. The decrease reflects the payment of the 2014 Senegal joint venture FAN-1 and SNE-1 well costs during the year. Included in trade and other payables of $18,761,407 at 31 December 2015 are $17,790,502 of Senegal joint operation payables relating to the SNE-2, SNE-3 and BEL-1 2015 well program.

As at 31 December 2015 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 started evaluation of two discoveries made in the 2014 year. 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 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 venture partners and operators, regular monitoring of the performance of operators in accordance with the Group’s policies; recruitment and retention of appropriately qualified employees and contractors, establishment and use of Group-wide risk management system. In addition, the Group implements insurance programs in place and specific insurance policies in relation to drilling operations that are consistent with good industry practice.

JOINT OPERATION RISK

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

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

GOVERNMENT AND REGULATOR RISK

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

In early May 2015, FAR and its joint operation partners submitted a three year evaluation work program to the Government of Senegal. This was subsequently approved by a Presidential decree which extends the current Petroleum Sharing Contract (‘PSC’) by the requested three years starting from 6 February 2016. The evaluation work program includes an initial, firm, three well drilling program (SNE-2, SNE-3 and BEL-1) and a 2,400km[2] 3D seismic survey over the Sangomar and Rufisque Blocks. This work program is expected to be followed by further drilling and geological and engineering studies in order to confirm commerciality of a development project and upon success, leading to the exploitation phase under the PSC.

In September 2015, the Polarcus Adira vessel began the new Senegal joint operation 3D seismic survey over FAR’s Sangomar and Rufisque Blocks. FAR also independently awarded Polarcus a contract to undertake a new 400km[2] 3D seismic survey in the western part of the Djiffere Block. Both 3D seismic surveys were completed efficiently in November 2015 and final processed products are expected from Q4 2016.

2015 FAR Annual Report 19

Directors’ Report

In September 2015, FAR announced it had 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. Under its 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 (subject to Government approvals). The farm-in option can be exercised by FAR at any time before 31 October 2016, by which time FAR expects to have completed its firm 3 well shelf drilling program.

In October 2015, FAR and its Senegal joint operation partners executed contracts for the use of the Ocean Rig Athena drillship for the Senegal drilling program. Ocean Rig Athena is a new, 7th generation, dual derrick, dynamically positioned drill ship (Enhanced SAIPEM10000 design) that was first delivered on 24 March, 2014.

In November 2015, FAR announced the commencement of the appraisal drilling program and it announced the results of the successful SNE-2 appraisal well and flow test on 4 January 2016. The SNE-2 well was safely drilled, cored, logged and tested ahead of schedule and oil flows from the drill stem testing (DST) demonstrated SNE is a world class oil discovery with the ability to flow oil at commercially viable rates. A DST of a 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. A DST of a shallower reservoir unit over a 15m interval (~3.5m net) flowed oil at a maximum rate of ~1,000 bopd on a 24/64” choke.

In 8 February 2016, FAR announced that an Independent Resources Report had been completed by RISC for FAR’s SNE oil discovery, offshore Senegal. The report was prepared as at December 2015 incorporating recent data available from wells SNE-1 and FAN-1 and reprocessed 3D seismic. This report upgraded SNE recoverable contingent resources to 1C: 240 mmbbls (prior 150 mmbbls), 2C: 468 mmbbls (prior 330 mmbbls) and 3C: 940 mmbbls (prior 670 mmbbls).

Kenya L6

FAR continued discussions with the Government of Kenya to secure a one year extension to the current Petroleum Sharing Contract to allow exploration activity that has been hindered by recent tensions on ground, to commence. FAR is planning for a 2D seismic survey to commence as soon as possible. Under the terms of the Joint Operating Agreement, FAR has issued a default notice to it’s partner (Pancontinental Oil and Gas NL) for continued failure to pay two cash calls from 12 Feb 2015. See Note 18(ii) for further details.

Kenya L9

In September 2013, FAR completed negotiations on joint operation agreements with the Operator, Ophir Energy PLC (‘Ophir’), on the offshore Kenya exploration permit Block L9. The assignment agreement between FAR and Ophir Energy (the Operator of Block L9) expired on 23 July 2014. Following this date, FAR and Ophir Energy have held discussions regarding FAR’s entry into the block and the plans for a future work program in the permit but are yet to reach resolution and the formalisation of FAR’s 30% equity interest in the block. FAR hopes to resolve this issue in 2016.

Guinea-Bissau

In late April 2015, the Government of Guinea-Bissau approved a 2 year extension to the current exploration term. The extension period begins on 26 November 2015. In February 2015, the joint operation acquired additional 3D seismic over the shelf edge to image prospects identified in this region that are potentially analogous to the SNE discovery, offshore Senegal. This new 3D data has been specifically designed to evaluate the large Atum prospect which was previously only partially covered by 3D data. The new seismic data is being processed and was delivered in Q4 of 2015.

Western Australia

FAR participated in a speculative 3D seismic survey that commenced Q2 2015 and data was acquired over 62% of the WA-458-P permit. Final processed products from the survey are expected to be delivered at end of Q2 2016. Data acquisition was restricted over the Glomar Shoals area in the permit and complete coverage is expected to be made in 2016.

Subsequent events

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 the upper ‘heterolithic’ 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). The RISC report is expected to be updated with the data provided from SNE-2, SNE-3 and BEL-1 in the future.

On 9 March 2016, FAR announced successful completion of the SNE-3 appraisal well. This well demonstrated the ability of SNE field upper reservoir units to flow at commercially viable rates and make a material contribution to oil volumes. Two drill stem tests (DST) have confirmed the deliverability of the upper reservoir units. 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 that was combined with the first flow has produced at a stabilised flow rate of 4,500 bopd (56/64” choke). Flow rates were equipment constrained, exceeded FAR pre-drill expectations, and have confirmed excellent reservoir quality and correlation between SNE-1, SNE-2 and SNE-3. SNE-3 results are expected to support a further upgrade of SNE field resource estimates.

Other than the above, the Directors are not aware of any other matters or circumstances at the date of this report that have significantly affected or may significantly affect the operations, the results of the operations or the state of affairs of the Group in subsequent financial years.

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.

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:

	Board of Directors’ Meetngs	Remuneraton & Nominaton Commitee Meetngs	Audit Commitee meetngs	Audit Commitee meetngs
	Held Atended	Held Atended	Held Atended
N J Limb	6 6	2 2	4	3
C M Norman	6 6	- -	-	-
B J M Clube	6 6	- -	-	-
R G Nelson	5 5	2 2	3	3
A E Brindal	6 6	2 2	4	4
C L Cavness	1 1	- -	1	1

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.

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

The Board has considered its position and, in accordance with the advice received from the Audit Committee, is satisfied that the provision of non-audit services, during the year, by the Auditor (or by another person or firm on the auditor’s behalf) is compatible with the general standard of independence for auditors imposed by the Corporations Act 2001.

The directors are of the opinion that the services as disclosed in Note 26 to the financial statements do not compromise the external auditors’ independence, based on advice received from the Audit Committee, for the following reasons:

all non-audit services have been reviewed and approved to ensure that they do not impact the integrity of the auditor: and
none of the services undermine the general principles relating to auditor independence as set out in APES 110 ‘Code of Ethics for Professional Accountants’ issued by the Accounting Professional & Ethical Standards Board, including reviewing or auditing the auditor’s own work, acting in management or decision making capacity for the company, acting as advocate for the company or jointly sharing economic risks and rewards.

2015 FAR Annual Report 21

Directors’ Report

AUDITOR’S INDEPENDENCE DECLARATION

The auditor’s independence declaration is included on page 30 of the Annual Report.

REMUNERATION REPORT – AUDITED

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 2015. 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 principles;
relationship between the remuneration policy and company performance;
remuneration of key management personnel;
key terms of employment contracts.

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-Executive Directors

Nicholas James Limb – Chairman, Non-Executive Director

Reginald George Nelson (appointed 9 April 2015) – Non-Executive Director

Albert Edward Brindal – Non-Executive Director

Charles Lee Cavness (resigned 15 May 2015) – Non-Executive Director

Executive Officers

Catherine Margaret Norman – Managing Director

Benedict James Murray Clube – Executive Director, Chief Operating Officer

Peter John Nicholls – Exploration Manager

Peter Anthony Thiessen – Chief Financial Officer and Company Secretary

Gordon Ramsay (appointed 1 February 2015) – Executive General Manager Business Development

Remuneration principles

The Company’s approach to remuneration is for remuneration levels to be set competitively with those terms offered by other entities of similar size within the petroleum industry. This allows FAR Ltd to attract, retain and motivate appropriately qualified and experienced directors and senior executives.

The Remuneration Committee provides recommendations to the Board on appropriate remuneration packages.

Remuneration packages for executives are not linked to profit performance as the Company is an exploration and appraisal company that is not generating profits or net operating cash flows and as such does not pay any dividends. It is the performance of the overall exploration and appraisal program and commercial transactions and ultimately the share price that largely determines FAR Ltd’s performance. The Remuneration Committee therefore considered that fixed compensation combined with long and short term incentives components is the best remuneration structure for achieving the Company’s objectives to the benefit of shareholders.

The present remuneration approach is to reward successful performance in recognition of adding shareholder value via incentive options that are priced at a premium to the market at the time of issue. The number of options granted is at the full discretion of the Board, subject to any necessary shareholder approvals.

The Group has established a Remuneration Committee for the purpose of recommending Executive Director, Non-Executive Director and senior executive remuneration to the Board. Remuneration of other personnel is set by the Managing Director.

Compensation for Non-Executive Directors is set based on comparison with reference to fees paid to non-executive directors of comparable companies. Non-Executive Director fees cover all main Board activities and membership of committees.

The Remuneration Committee are reviewing the current remuneration practices of the Company and formulating a remuneration policy to ensure the Company is more closely aligned with current market practice. It is intended a synopsis of this review will be disclosed in the upcoming Notice of Annual General Meeting.

Relationship between the Remuneration Policy and Company Performance

As noted above, remuneration packages were not linked to profit performance during the 2015 year.

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.

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

The tables below set out summary information about the Group’s earnings and movements in shareholder wealth for the five years to 31 December 2015:

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|||||||
|---|---|---|---|---|---|
|31 Dec 2015|31 Dec 2014|31 Dec 2013|31 Dec 2012|31 Dec 2011|
|(restated)|(restated)|
|$|$|$|$|$|
|Revenue|287,088|629,293|583,210|1,192,665|1,637,279|
|Loss from continuing operations|(19,620,114)|(6,937,168)|(7,955,349)|(14,474,951)|(39,326,180)|
|Loss from continuing & discontinued operations|(19,620,114)|(6,937,168)|(7,957,039)|(14,422,029)|(39,841,385)|
|31 Dec 2015|31 Dec 2014|31 Dec 2013|31 Dec 2012|31 Dec 2011|
|Share price at start of year|8.6 cents|4.0 cents|3.4 cents|2.8 cents|8.2 cents|
|Share price at end of year|8.3 cents|8.6 cents|4.0 cents|3.4 cents|2.8 cents|
|Dividend|-|-|-|-|-|
|Basic loss per share|0.57 cps|0.26 cps|0.32 cps|0.60 cps|2.97 cps|
|Diluted loss per share|0.57 cps|0.26 cps|0.32 cps|0.60 cps|2.97 cps|

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Some prior year amounts have been restated to reflect the change in accounting policy in respect of the treatment of exploration expenditure adopted by the Board during the 2013 year.

Remuneration of key management personnel

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|||||||||||
|---|---|---|---|---|---|---|---|---|---|
|2015|Short-term employee benefits|Post-|Share-based|Long service|Total|
|employment|payment|leave|
|Name|Salary|Bonus|Non-|Other|Super|Options|
|and fees|monetary|
|Non-Executive Directors|
|N J Limb|150,000|-|-|-|-|-|-|150,000|
|A E Brindal|50,000|-|-|-|-|-|-|50,000|
|C L Cavness|20,833|-|-|-|-|-|-|20,833|
|R G Nelson|49,658|-|-|-|4,717|81,667|-|136,042|
|Executive officers|
|C M Norman|520,000|-|-|10,216|30,000|163,333|14,079|737,628|
|B J M Clube|445,000|-|-|19,279|30,000|130,667|6,425|631,371|
|P J Nicholls|[ (iii)]|447,300|-|-|-|-|130,667|-|577,967|
|P A Thiessen|250,000|-|-|3,996|30,000|130,667|2,418|417,081|
|-|-|
|G A Ramsay|380,417|23,719|32,083|130,667|1,033|567,919|
|3,288,841|

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2015 FAR Annual Report 23

Directors’ Report

2014		Short-term	employee benefts	employee benefts	Post-	Share-based	Long service	Total
					employment	payment	leave
Name	Salary and fees	Bonus	Non- monetary	Other	Super	Optons
Non-Executve Directors
N J Limb	127,083		-	-	- -	-	-	127,083
A E Brindal	50,000		-	-	- -	-	-	50,000
C L Cavness	50,000		-	-	- -	-	-	50,000
Executve ofcers
C M Norman	412,806	100,000		- 52,762 27,500		-	52,007	645,075
B J M Clube	348,829	75,000		- 29,008 27,500		-	4,136	484,473
P J Nicholls(i)	357,789		-	-	- -	-	-	357,789
P A Thiessen	207,502	50,000		-	24 27,500	-	2,441	287,467
								2,001,887

(i) Mr Nicholls is a consultant and not an employee of the Company. For further details see below.

Key terms of employment contracts

Name	Contract duraton Terminaton notce by the company Terminaton notce by the executve
C M Norman	Ongoing, no fxed term 12 months 3 months
B J M Clube	Ongoing, no fxed term 12 months 3 months
P A Thiessen	Ongoing, no fxed term 12 months 2 months
G A Ramsay	Ongoing, no fxed term 12 months 2 months
P J Nicholls	Ongoing, no fxed term By giving notce of a breach of contract

Bonus and share-based payments

Cash bonuses

No cash bonuses were granted during 2015.

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. 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 from the date of vesting to the date of expiry.

Terms and conditions of the share-based payment arrangements affecting remuneration of key management personnel in existence during the financial year were as follows:

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Options series Grant date Grant date fair value Exercise price Expiry date Vesting date
Series 7 31 May 2012 2.1 cents 6.0 cents 30 Jun 2015 Vests at the date of grant
Series 8 23 Jul 2012 2.9 cents 6.0 cents 23 Jul 2015 Vests at the date of grant
Series 9 21 Aug 2012 2.5 cents 6.0 cents 30 Jun 2015 Vests at the date of grant
Series 10 27 May 2013 1.6 cents 4.4 cents 27 May 2016 Vests at the date of grant
Series 11 1 Jul 2015 8.7 cents 10.0 cents 1 Jun 2018 Vests on the announcement
to the effect of potential
economic viability of a future
development project by
the Senegal joint venture
Operator before 1 June 2018
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Details of share-based payments granted as compensation to key management personnel during the current financial year:

Name Opton series R G Nelson Series 11	During the fnancial year
	No. granted No. vested % of grant vested % of grant forfeited
	5,000,000 - - -
C M Norman Series 11	10,000,000 - - -
B J M Clube Series 11	8,000,000 - - -
P J Nicholls Series 11	8,000,000 - - -
G A Ramsay Series 11	8,000,000 - - -
P A Thiessen Series 11	8,000,000 - - -

During the year, the following key management personnel exercised options that were granted to them as part of their compensation. Each option converts into one ordinary share of FAR Ltd.

Name	No. of optons exercised No. of ordinary shares of FAR Ltd issued Amount paid Amount unpaid
C M Norman	20,000,000 20,000,000 $1,200,000 $nil
B J M Clube	10,000,000 10,000,000 $600,000 $nil
P J Nicholls	10,000,000 10,000,000 $600,000 $nil
P A Thiessen	6,000,000 6,000,000 $360,000 $nil

The following table summarises the value of options granted and exercised during the financial year, in relation to options granted to key management personnel as part of their remuneration:

Name R G Nelson	Value of optons granted at the grant date(i) $ Value of optons exercised at the exercise date(ii) $
	81,667 -
C M Norman	163,333 380,000
B J M Clube	130,667 200,000
P J Nicholls	130,667 190,000
G A Ramsay	130,667 -
P A Thiessen	130,667 114,000

(i) The value of options granted during the financial year is calculated as at the grant date using a Black Scholes pricing model. The grant date value is allocated to remuneration of key management personnel on a straight-line basis over the period from grant date to vesting date.

(ii) The value of options exercised during the financial year is calculated as at the exercise date using a Black Scholes pricing model.

2015 FAR Annual Report

Directors’ Report

Key management personnel equity holdings

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

in the tables below.
For the year ended 31 Dec 2015	Balance 1 Jan 15 Received on Exercise of Optons Net Other Change Balance 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 Executves P J Nicholls	4,534,291 10,000,000 (10,000,000) 4,543,291
P A Thiessen	- 6,000,000 (4,937,500) 1,062,500
G A Ramsay(iii)	- - 550,000 550,000
For the year ended 31 Dec 2014	41,406,908 46,000,000 (29,085,933) 58,320,975

	Balance 1 Jan 14 Received on Exercise of Optons Net Other Change Balance 31 Dec 14
Directors C M Norman	574,417 - - 574,417
B J M Clube	1,920,000 - - 1,920,000
N J Limb	32,908,139 - - 32,908,139
C L Cavness	1,150,000 - - 1,150,000
A E Brindal	311,061 - - 311,061
Key Executves P J Nicholls	4,543,291 - - 4,543,291
P A Thiessen	- - - -
	41,406,908 - - 41,406,908

(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 on 1 February 2015.

Key management personnel option holdings

For the year ended 31 Dec 2015	Balance 1 Jan 15 Optons Granted as Compensaton Optons Exercised Net Other Change Balance 31 Dec 15
Directors C M Norman	34,000,000 10,000,000 (20,000,000) - 24,000,000
B J M Clube	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 Executves P J Nicholls	20,000,000 8,000,000 (10,000,000) - 18,000,000
P A Thiessen	12,000,000 8,000,000 (6,000,000) - 14,000,000
G A Ramsay	- 8,000,000 - - 8,000,000
	93,000,000 47,000,000 (46,000,000) - 94,000,000

For the year ended 31 Dec 2014	Balance 1 Jan 14 Optons Granted as Compensaton Optons Exercised Net Other Change Balance 31 Dec 14
Directors C M Norman	34,000,000 - - - 34,000,000
B J M Clube	22,000,000 - - - 22,000,000
N J Limb	5,000,000 - - - 5,000,000
Key Executves P J Nicholls	20,000,000 - - - 20,000,000
P A Thiessen	12,000,000 - - - 12,000,000
	93,000,000 - - - 93,000,000

The options granted as compensation in the current year vest on the announcement to the effect of potential economic viability of a future development project by the Senegal joint operation Operator before 1 June 2018.

Further details of share options granted to directors and executives during the year have been disclosed at Note 22 to the financial statements

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 2016

2015 FAR Annual Report 27

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Financial Report 2015

FAR moves into 2016 with a robust cash position, driven by its conservative financial policy and efficient Senegal drilling

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2015 FAR Annual Report 29

Auditor’s Independence Declaration

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Independent Auditor’s Report

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2015 FAR Annual Report

Independent Auditor’s Report

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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 2016

2015 FAR Annual Report 33

Consolidated Statement of Profit or Loss and Other Comprehensive Income For the financial year ended 31 December 2015

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|||||
|---|---|---|---|
|Year ended|Year ended|
|31 Dec 2015|31 Dec 2014|
|Note|AU$|AU$|
|Interest income|287,088|629,293|
|-|
|Gain on recovery of back costs|688,622|
|Depreciation expense|6|(44,327)|(21,741)|
|Exploration expense|6|(16,674,745)|(7,703,788)|
|Finance costs|-|(639)|
|Corporate administration expenses|(635,823)|(605,691)|
|Employee benefits expense|6|(3,102,003)|(1,648,717)|
|Consulting expense|6|(545,157)|(532,569)|
|Foreign exchange gain|1,333,165|2,430,286|
|Other expenses|(238,312)|(172,224)|
|Loss before income tax|(19,620,114)|(6,937,168)|
|-|-|
|Income tax expense|7(a)|
|LOSS FOR THE YEAR|(19,620,114)|(6,937,168)|
|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|3,473,530|(391,627)|
|Other comprehensive gain / (loss) for the year, net of the income tax|3,473,530|(391,627)|
|TOTAL COMPREHENSIVE LOSS FOR THE YEAR|(16,146,584)|(7,328,795)|
|Earnings per share:|
|From continuing operations|
|Basic loss (cents per share)|15|(0.57)|(0.26)|
|Diluted loss (cents per share)|15|(0.57)|(0.26)|

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Notes to the financial statements are included on pages 38 to 64.

Consolidated Statement of Financial Position

As at 31 December 2015

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|||||
|---|---|---|---|
|Year ended|Year ended|
|Note|31 Dec 2015|31 Dec 2014|
|AU$|AU$|
|CURRENT ASSETS|
|Cash and cash equivalents|20(a)|60,670,897|67,225,297|
|Trade and other receivables|8|1,841,315|2,846,249|
|Other financial assets|9|116,007|85,778|
|Total Current Assets|62,628,219|70,157,324|
|NON CURRENT ASSETS|
|Property, plant and equipment|10|346,186|153,410|
|Exploration and evaluation assets|11|58,861,246|34,124,907|
|Total Non-Current Assets|59,207,432|34,278,317|
|TOTAL ASSETS|121,835,651|104,435,641|
|CURRENT LIABILITIES|
|Trade and other payables|12|18,761,407|28,528,694|
|Provisions|13|696,155|558,395|
|Total Current Liabilities|19,457,562|29,087,089|
|NON-CURRENT LIABILITIES|
|Provisions|13|89,819|60,382|
|Total Non-Current Liabilities|89,819|60,382|
|TOTAL LIABILITIES|19,547,381|29,147,471|
|NET ASSETS|102,288,270|75,288,170|
|EQUITY|
|Issued Capital|14|237,806,280|195,770,263|
|Reserves|8,382,731|4,470,030|
|Accumulated losses|(143,900,741)|(124,952,123)|
|TOTAL EQUITY|102,288,270|75,288,170|

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Notes to the financial statements are included on pages 38 to 64.

2015 FAR Annual Report 35

Consolidated Statement of Changes in Equity For the financial year ended 31 December 2015

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|||||||||||
|---|---|---|---|---|---|---|---|---|---|
|Reserves|
|Equity|Foreign|Total|
|component|currency|attributable to|
|Option|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 2014|143,384,588|4,844,555|671,496|(654,394)|4,861,657|(118,014,955)|30,231,290|
|-|-|-|-|-|
|Loss for the year|(6,937,168)|(6,937,168)|
|Other Comprehensive|
|losses for the year,|
|net of income tax|-|-|-|(391,627)|(391,627)|(391,627)|
|Total comprehensive|
|-|-|-|
|loss for the year|(391,627)|(391,627)|(6,937,168)|(7,328,795)|
|-|-|-|-|-|
|Issue of ordinary shares|54,745,785|54,745,785|
|Issue of ordinary shares|
|-|-|-|-|-|
|under share option plan|120,000|120,000|
|Share issue costs|(2,480,110)|-|-|-|-|-|(2,480,110)|
|Balance at|
|31 December 2014|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/(loss) 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|

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(i) Option reserve represents share based payments made to directors and employees of the Company.

(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 38 to 64.

Consolidated Statement of Cash Flows

For the financial year ended 31 December 2015

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|||||
|---|---|---|---|
|Year ended|Year ended|
|31 Dec 2015|31 Dec 2014|
|Note|AU$|AU$|
|CASH FLOWS FROM OPERATING ACTIVITIES|
|Payments to suppliers and corporate employees|(3,288,953)|(2,812,544)|
|Payment for exploration and evaluation expensed|(15,829,833)|(8,492,995)|
|-|
|Interest and other costs of finance paid|(639)|
|Net cash used in operating activities|20(d)|(19,118,786)|(11,306,178)|
|CASH FLOWS FROM INVESTING ACTIVITIES|
|Interest received|361,279|587,905|
|Payments for exploration and evaluation assets capitalised|(32,063,725)|(17,573,882)|
|Payments for property, plant and equipment|(270,395)|(54,755)|
|Proceeds from farm-out of exploration and evaluation assets|7,315,660|
|Farm-out proceeds funding well costs|9,572,520|
|Proceeds from security deposits|1,961|
|Advance from / (to) Joint Operation|45,657|(113,254)|
|-|
|Payment of performance bonds|(31,250)|
|Net cash used in investing activities|(31,958,434)|(263,845)|
|CASH FLOWS FROM FINANCING ACTIVITIES|
|Proceeds from issue of shares|44,017,333|54,865,785|
|Payment for share issue costs|(1,981,316)|(2,480,110)|
|Net cash provided by financing activities|42,036,017|52,385,675|
|NET (DECREASE) / INCREASE IN CASH AND CASH EQUIVALENTS|(9,041,203)|40,815,652|
|Cash and cash equivalents at the beginning of the year|67,225,297|24,203,117|
|Effects of exchange rate changes on cash and cash equivalents|2,486,803|2,206,528|
|Cash and cash equivalents at the end of the financial year|20(a)|60,670,897|67,225,297|

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Notes to the financial statements are included on pages 38 to 64.

2015 FAR Annual Report 37

Notes to the Financial Statements For the financial year ended 31 December 2015

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1. GENERAL INFORMATION

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

FAR Ltd’s registered office and its principal place of business at the date of this report is as follows: Level 17, 530 Collins Street Melbourne VIC 3000 Tel: (03) 9618 2550

2. ADOPTION OF NEW AND REVISED ACCOUNTING STANDARDS

In the current period, the Group has adopted all of the new and revised Standards and Interpretations issued by the Australian Accounting Standards Board (the ‘AASB’) that are relevant to its operations and effective for reporting periods beginning on 1 January 2015.

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 2015|Effective|
|AASB 2010-7 Amendments to Australian Accounting Standards arising from AASB 9|1 Jan 2016|
|AASB 2014-1 (Part E) Amendments to Australian Accounting Standards – Financial Instruments|1 Jan 2016|
|AASB 2014-3 Accounting for Acquisitions of Interests in Joint Operations|1 Jan 2016|
|AASB 2014-4 Clarification of Acceptable Methods of Depreciation and Amortisation|1 Jan 2016|
|AASB 2014-5 Amendments to Australian Accounting Standards arising from AASB 15|1 Jan 2018|
|AASB 2014-7 Amendments to Australian Accounting Standards arising from AASB 9 (December 2014)|1 Jan 2018|
|AASB 2014-9 Equity Method in Separate Financial Statements|1 Jan 2016|
|AASB 2014-10 Sale or Contribution of Assets between an Investor and its Associate or Joint Venture|1 Jan 2016|
|AASB 2015-1 Annual Improvements to Australian Accounting Standards 2012-2014 Cycle|1 Jan 2016|
|AASB 2015-2 Disclosure Initiative: Amendments to AASB 101|1 Jan 2016|
|AASB 2015-3 Amendments to Australian Accounting Standards arising from Withdrawal of AASB 1031 Materiality|1 Jan 2016|
|AASB 2015-8 Amendments to Australian Accounting Standards – Effective Date of AASB 15|1 Jan 2018|
|AASB 15 Revenue from Contracts with Customers|1 Jan 2018|
|AASB 9 Financial Instruments 2014|1 Jan 2018|
|AASB 16 Leases|1 Jan 2019|

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

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|||
|---|---|
|Recognition of Deferred Tax Assets for Unrealised Losses (Amendments to IAS 12)|1 Jan 2018|
|Disclosure Initiative (Amendments to IAS 7)|1 Jan 2018|

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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 2015.

(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 revalued amounts or 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.

rights arising from other contractual arrangements; and
any additional facts and circumstances that indicate that the Company has, or does not have, the current ability to direct the relevant activities at the time that decisions need to be made, including voting patterns at previous shareholders’ meeting.

Consolidation of a subsidiary begins when the Company obtains control over the subsidiary and ceases when the Company loses control of the subsidiary. Specifically, 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.

Profit or loss and each component of other comprehensive income are attributed to the owners of the Company and to the non-controlling interest. Total comprehensive income of subsidiaries is attributed to the owners of the Company and to the non-controlling interests even if this results in the noncontrolling interests having a deficit balance.

When necessary, adjustments are made to the financial statements of subsidiaries to bring their accounting policies into line with those used by other members of the Group.

All intra-group assets and liabilities, equity, income, expenses and cash flows relating to transactions between members of the Group are eliminated in full on consolidation.

(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 2015, the Group’s current assets exceeded current liabilities by $43,170,657 and the Group has cash and cash equivalents of $60,670,897. The Group will continue to manage its evaluation and operating activities and put in place financing arrangements to ensure that it has sufficient cash reserves for the next twelve months. The Group will likely require funding within the next twelve months to fund 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.

2015 FAR Annual Report 39

Notes to the Financial Statements For the financial year ended 31 December 2015

(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.

(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 as held-for-trading or designated as at fair value through profit or loss. Financial assets held for trading purposes are classified as current assets and are stated at fair value, with any resultant gain or loss recognised in profit or loss.

Held-to-maturity investments

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

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

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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.

With the exception of available-for-sale equity instruments, if, in a subsequent period, the amount of the impairment loss decreases and the decrease can be related objectively to an event occurring after the impairment was recognised, the previously recognised impairment loss is reversed through profit or loss to the extent the carrying amount of the investment at the date the impairment is reversed does not exceed what the amortised cost would have been had the impairment not been recognised.

In respect of available-for-sale equity instruments, any subsequent increase in fair value after an impairment loss is recognised directly in equity.

(i) Financial instruments issued by the Company

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(h).

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.

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(j) Provisions

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

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

(k) Foreign currency translation

Functional and presentation currency

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

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

Transactions and balances

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

Group companies and foreign operations

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

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

(l) Income tax

Current tax

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

Deferred tax

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

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

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

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

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

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

Tax consolidation

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

2015 FAR Annual Report 41

Notes to the Financial Statements For the financial year ended 31 December 2015

(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.

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

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(p) Exploration and evaluation costs

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

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

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

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

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

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

(q) Property, plant and equipment

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

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

Furniture, fittings and equipment: 10-40%

Interest revenue

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

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.

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(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.

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.

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 are the critical judgements, including those involving estimations, that management has made in the process of applying the Group’s accounting policies and that have the most significant effect on the amounts recognised in the financial statements:

(i) The Group recognises any obligations for removal and restoration that are incurred during a particular period as a consequence of having undertaken exploration and evaluation activity. Future restoration and abandonment obligations are reviewed annually taking into account estimates by independent petroleum engineers. Presently the Group does not have any large scale production facilities that would have a material impact in relation to future restoration costs and, accordingly, there are no provisions for future restoration costs. This position may change should the Group embark on a more substantial development project.
(ii) 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.
(iii) The Group has carried forward tax losses which have not been recognised as deferred tax assets as it is not considered sufficiently probable at this point in time that these losses will be recouped by means of future profits taxable in the relevant jurisdictions.
(iv) The Group measures the cost of equity settled share-based payments at fair value at the grant date using an appropriate valuation model taking into account the terms and conditions upon which the instruments were granted and expected vesting period as disclosed in Note 22.

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.

2015 FAR Annual Report 43

Notes to the Financial Statements For the financial year ended 31 December 2015

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

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 2015|31 Dec 2014|31 Dec 2015|31 Dec 2014|
|AU$|AU$|AU$|AU$|
|AGC|9,445|11,711|4,727|5,457|
|Guinea-Bissau|1,483,114|1,639,094|83,743|89,378|
|Kenya|775,312|774,699|46,808|102,376|
|Senegal|69,385,449|36,087,271|17,790,502|27,797,410|
|USA|107,901|100,647|-|-|
|Corporate|50,074,430|65,822,219|1,621,601|1,152,850|
|Total assets and liabilities|121,835,651|104,435,641|19,547,381|29,147,471|

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Segment revenue and results

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

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||||||
|---|---|---|---|---|
|Interest Income|Segment Loss|
|Year ended|Year ended|Year ended|Year ended|
|31 Dec 2015|31 Dec 2014|31 Dec 2015|31 Dec 2014|
|AU$|AU$|AU$|AU$|
|AGC|-|-|(2,203)|(1,352,934)|
|Australia|-|-|(1,363,424)|(621,164)|
|Guinea-Bissau|-|-|(1,377,989)|(642,576)|
|-|-|
|Kenya|(297,183)|(913,879)|
|-|-|
|Senegal|(12,611,392)|(3,712,948)|
|Other|314|280|(1,027,644)|(335,942)|
|Corporate|286,774|629,013|(2,940,279)|642,275|
|Total for continuing operations|287,088|629,293|(19,620,114)|(6,937,168)|
|-|-|
|Income tax expense|
|Loss before tax (continuing operations)|(19,620,114)|(6,937,168)|

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

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Other segment information

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||||||
|---|---|---|---|---|
|Depreciation|Additions to Non-Current Assets|
|Year ended|Year ended|Year ended|Year ended|
|31 Dec 2015|31 Dec 2014|31 Dec 2015|31 Dec 2014|
|AU$|AU$|AU$|AU$|
|Guinea-Bissau|-|-|344|585,168|
|-|-|
|Kenya|5,905|33,916|
|-|-|
|Senegal|20,546,412|29,564,528|
|Corporate|44,327|21,741|270,395|54,755|
|Total|44,327|21,741|20,823,056|30,238,367|

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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 2015|31 Dec 2014|
|AU$|AU$|
|Depreciation:|
|- Property, plant & equipment|(77,619)|(49,587)|
|- Recharge of depreciation to exploration expenditure|33,292|27,846|
|(44,327)|(21,741)|
|Exploration Expense:|
|- AGC|(2,203)|(1,352,934)|
|- Australia|(1,363,424)|(621,164)|
|- Guinea-Bissau|(1,377,989)|(642,576)|
|- Senegal|(12,611,392)|(3,712,948)|
|- Kenya|(297,183)|(913,879)|
|- Other|(1,022,554)|(460,287)|
|(16,674,745)|(7,703,788)|
|Consulting expenses:|
|- Corporate and other consulting costs|(545,157)|(532,569)|
|(545,157)|(532,569)|
|Employee benefit expense:|
|- Short-term employee benefits – salaries and fees|(2,737,659)|(2,118,959)|
|- Recharge of salaries and fees to exploration expenditure|1,099,030|877,563|
|Post-employment benefits:|
|- Defined contribution plans|(193,879)|(126,905)|
|-|
|- Share based payments-equity settled|(1,110,667)|
|- Increase in employee benefits provisions|(158,828)|(280,416)|
|(3,102,003)|(1,648,717)|

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2015 FAR Annual Report 45

Notes to the Financial Statements

For the financial year ended 31 December 2015

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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 2015|31 Dec 2014|
|AU$|AU$|
|Tax (income) comprises:|
|Current tax expense|(487,197)|(853,761)|
|Tax losses not brought to account|487,197|853,761|
|Deferred tax (income) relating to the origination and reversal of temporary differences|(794,066)|(85,650)|
|Benefit arising from previously recognised tax losses of prior periods|
|used to reduce deferred tax expense|794,066|85,650|
|Prior year unders / overs|(104,848)|(372,168)|
|Utilisation of previously unrecognised tax losses|104,848|372,168|
|-|-|
|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 2015|31 Dec 2014|
|AU$|AU$|
|Loss from operations|(19,620,114)|(6,937,168)|
|Income tax (income) calculated at 30%|(5,886,034)|(2,081,150)|
|Non-deductible expenses|4,885,230|2,160,728|
|Non-assessable gains / (loss)|596,398|(852,855)|
|Recognition of previously unrecognised deductible temporary differences|(82,791)|(80,484)|
|Unused tax losses and tax offsets not recognised as deferred tax assets|487,197|853,761|
|-|-|

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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|
|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|(421,426)|235,792|
|Total|178,836|(794,067)|(143,647)|

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|||||
|---|---|---|---|
|Recognised|Closing|
|Opening balance|in income|balance|
|2014|AU$|AU$|AU$|
|Property, plant & equipment|(1,421)|580|(841)|
|Receivables|150,487|(173,329)|(22,842)|
|Payables|13,911|2,974|16,885|
|Provisions|101,509|84,125|185,634|
|Total|264,486|(85,650)|178,836|

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||||
|---|---|---|
|31 Dec 2015|31 Dec 2014|
|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)|178,836|
|Tax losses in the United States (net)|4,683,844|4,162,989|
|Tax losses in Australia (net)|12,809,579|11,769,643|
|Capital losses in Australia|99,257|99,257|
|17,592,680|16,210,725|

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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.

2015 FAR Annual Report 47

Notes to the Financial Statements

For the financial year ended 31 December 2015

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8. TRADE AND OTHER RECEIVABLES

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|||||
|---|---|---|---|
|31 Dec 2015|31 Dec 2014|
|AU$|AU$|
|Current|
|Interest receivable|1,942|76,142|
|Other receivables|348,467|401,055|
|Prepayments|167,773|90,733|
|Joint operation receivables|[ (i)]|1,323,133|31,225|
|-|
|Joint operation prepayments|[(ii)]|2,247,094|
|1,841,315|2,846,249|

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(i) Includes Senegal joint operation receivables of $1,185,330 (2014: $nil).

(ii) Includes Senegal joint operation prepayments of $nil (2014: $2,247,094).

9. OTHER FINANCIAL ASSETS

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||||
|---|---|---|
|31 Dec 2015|31 Dec 2014|
|Current|AU$|AU$|
|Joint operation security deposit|985|878|
|Joint operation performance bond|115,022|84,900|
|116,007|85,778|

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The weighted average interest rate on the performance bond is 2.83% (2014: 3.28%).

10. PROPERTY, PLANT AND EQUIPMENT

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|||
|---|---|
|Furniture, Fittings & Equipment|
|AU$|
|Cost|
|Balance at 1 January 2014|457,987|
|Additions|54,755|
|Balance at 31 December 2014|512,742|
|Additions|270,395|
|Balance at 31 December 2015|783,137|
|Accumulated depreciation and impairment|
|Balance at 1 January 2014|309,745|
|Depreciation expense|49,587|
|Balance at 31 December 2014|359,332|
|Depreciation expense|77,619|
|Balance at 31 December 2015|436,951|
|Net Book Value|
|31 December 2014|153,410|
|31 December 2015|346,186|

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11. EXPLORATION AND EVALUATION ASSETS

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|||||
|---|---|---|---|
|31 Dec 2015|31 Dec 2014|
|AU$|AU$|
|Exploration and evaluation expenditure:|34,124,907|2,209,140|
|Balance at 1 January|
|Additions|[(i)]|20,552,661|30,183,612|
|-|
|Recovery of back costs|[(ii)]|(1,029,814)|
|Net foreign currency exchange differences|[(i)]|4,183,678|2,761,969|
|Balance at 31 December|58,861,246|34,124,907|

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(i) Further to the FAN-1 and SNE-1 Senegal offshore wells drilled in 2014 the Company commenced the drilling of the Senegal offshore appraisal wells SNE-2 and SNE-3 in October 2015 with its joint operation partners Capricorn Senegal Limited (a subsidiary of Cairn Energy PLC) and ConocoPhillips. The Company’s participating share of SNE-2, SNE-3 and BEL-1 well costs for the 2015 year were $24,492,584, inclusive of net foreign exchange differences.

(ii) The recovery of back costs in the prior year represents the ConocoPhillips farm-in proceeds received in respect of the Senegal project.

12. TRADE AND OTHER PAYABLES

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|||||
|---|---|---|---|
|31 Dec 2015|31 Dec 2014|
|AU$|AU$|
|Current|
|Trade payables|[ (i)]|637,770|212,582|
|Other payables|216,996|321,490|
|Joint operation payables|[ (ii)]|17,906,641|27,994,622|
|18,761,407|28,528,694|

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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 $17,790,502 (2014: $27,797,411) relating predominantly to the drilling costs of the 3 well offshore appraisal and exploration program.

13. PROVISIONS

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||||
|---|---|---|
|31 Dec 2015|31 Dec 2014|
|AU$|AU$|
|Current|
|Employee benefits|696,155|558,395|
|Non-Current|
|Employee benefits|89,819|60,382|

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

2015 FAR Annual Report 49

Notes to the Financial Statements

For the financial year ended 31 December 2015

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14. ISSUED CAPITAL

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|||||||
|---|---|---|---|---|---|
|31 Dec 2015|31 Dec 2015|31 Dec 2014|31 Dec 2014|
|Number|AU$|Number|AU$|
|Paid up capital:|
|Ordinary fully paid shares|
|at beginning of year|3,126,808,427|195,770,263|2,499,846,742|143,384,588|
|Shares allotted during the year|[ (a)]|566,841,672|44,017,333|626,961,685|54,865,785|
|Share issue costs|(1,981,316)|-|(2,480,110)|
|Ordinary fully paid shares at end of year|3,693,650,099|237,806,280|3,126,808,427|195,770,263|

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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) 250,000 ordinary fully paid shares were issued at 6.0 cents upon the exercise of unlisted options on 4 February 2015.
(ii) 500,000 ordinary fully paid shares were issued at 6.0 cents upon the exercise of unlisted options on 8 April 2015.
(iii) 750,000 ordinary fully paid shares were issued at 6.0 cents upon the exercise of unlisted options on 21 April 2015.
(iv) 1,000,000 ordinary fully paid shares were issued at 6.0 cents upon the exercise of unlisted options on 20 May 2015.
(v) 1,000,000 ordinary fully paid shares were issued at 6.0 cents upon the exercise of unlisted options on 3 June 2015.
(vi) 53,000,000 ordinary fully paid shares were issued at 6.0 cents upon the exercise of unlisted options on 24 June 2015.
(vii) 10,000,000 ordinary fully paid shares were issued at 6.0 cents upon the exercise of unlisted options on 15 July 2015.
(viii) 312,500,000 ordinary fully paid shares were issued at 8.0 cents per share via a placement to institutional and sophisticated investors on 30 October 2015.
(ix) 187,841,672 ordinary fully paid shares were issued at 8.0 cents per share via a 1 for 17 rights issue to existing shareholders on 25 November 2015.

Share options outstanding at balance date

At balance date the Company had the following options available to be exercised:

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|||||||
|---|---|---|---|---|---|
|Option Series|Number|Grant date|Expiry date|Exercise|Fair value at|
|Price|grant date|
|AU$|AU$|
|Series 10|62,000,000|27 May 2013|27 May 2016|4.4 cents|1.6 cents|
|Series 11|68,000,000|1 Jul 2015|1 Jun 2018|10.0 cents|4.9 cents|
|130,000,000|

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15. EARNINGS PER SHARE

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||||
|---|---|---|
|31 Dec 2015|31 Dec 2014|
|Cents per share|Cents per share|
|Basic loss per share|
|From continuing operations|(0.57)|(0.26)|
|Diluted loss per share|
|From continuing operations|(0.57)|(0.26)|

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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 2015|31 Dec 2014|
|AU$|AU$|
|Loss:|
|Loss for the year attributable to members of FAR Ltd|(19,620,114)|(6,937,168)|
|(19,620,114)|(6,937,168)|
|Number|Number|
|Weighted average number of ordinary shares for the purposes of basic|
|and diluted loss per share|3,431,303,408|2,695,129,910|

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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 2015|31 Dec 2014|
|Number|Number|
|-|
|6.0 cents June 2015 unlisted options|56,500,000|
|-|
|6.0 cents July 2015 unlisted options|10,000,000|
|4.4 cents May 2016 unlisted options|62,000,000|62,000,000|
|-|
|10.0 cents June 2018 unlisted options|68,000,000|
|130,000,000|128,500,000|

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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 potentially 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 2015|31 Dec 2014|
|AU$|AU$|
|Exploration and evaluation assets|
|Not longer than 1 year|50,606,251|8,415,936|
|Longer than 1 year and not longer than 5 years|44,196,163|600,000|
|-|-|
|Longer that 5 years|
|94,802,514|9,015,936|

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2015 FAR Annual Report 51

Notes to the Financial Statements

For the financial year ended 31 December 2015

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17. CONTINGENT LIABILITIES

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|||||
|---|---|---|---|
|31 Dec 2015|31 Dec 2014|
|AU$|AU$|
|Contingent liabilities|
|Guinea-Bissau – contingent payment from future production|[ (i)]|17,793,594|15,849,793|
|Guinea-Bissau – contingent withholding tax liability|[ (ii)]|777,185|685,067|
|Kenya L6 – Performance Bond|[ (iii)]|115,022|84,900|
|18,685,801|16,619,760|

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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 17,793,594 (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. The joint operation aims to finalise a drill location in Guinea-Bissau in early 2017.
(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 2015 is $777,185.
(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 is the Contractor for the project and, in accordance with the terms of the Contract, the Contractor must provide security guaranteeing the Contractor’s minimum work and expenditure obligations on or before the commencement of an Exploration Period. This amount represents the Group’s share of the guarantee. The guarantee is payable on written demand where the Contractor is in default under the contract. Where the Contractor meets the minimum work and expenditure obligations of the Exploration Period the security is released. Security deposit equal to the contingent liability of $115,022 is disclosed in current, other financial assets, see Note 9.

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

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18. INTERESTS IN JOINT VENTURE 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 2015|31 Dec 2014|
|%|%|
|Australia|
|EP104|[ (i)]|-|15.7|
|R1|[ (i)]|-|8.9|
|L15|[ (i)]|-|12.0|
|Guinea-Bissau|
|Sinapa / Esperança|15.0|15.0|
|Kenya|
|L6|[ (ii)]|60.0|60.0|
|L9|[ (iii)]|30.0|30.0|
|Senegal|
|Rufisque Offshore / Sangomar Offshore / Sangomar Deep Offshore|15.0|15.0|
|-|-|
|Djiffere Block|[ (iv)]|

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(i) The Company executed a Deed of Sale, Assignment and Assumption with Key Petroleum Limited on 23 February 2015 to dispose its entire interest in EP104, R1 and L15. In consideration, with respect to the recent joint operation expenditures, and for Key Petroleum Limited assuming all rights, obligations and liabilities associated with the assignment of the permits, the Company agreed to pay $50,000 cash.
(ii) 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.

(iii) The assignment agreement between Petrole Investments Group Pty Ltd a wholly owned subsidiary of FAR Ltd (‘FAR’) and Dominion Petroleum (Kenya) Ltd a wholly owned subsidiary of Ophir Energy PLC (‘Ophir’) executed on 26 July 2013 in relation to an assignment of a 30% interest in Block L9 offshore Kenya, expired on 30 June 2014. The Group is currently seeking to resolve the status of its interest.
(iv) 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 its 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 (subject to Government approvals). The farm-in option can be exercised by FAR at any time before 31 October 2016.

2015 FAR Annual Report 53

Notes to the Financial Statements

For the financial year ended 31 December 2015

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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 2015|31 Dec 2014|
|AU$|AU$|
|Current Assets|
|Cash and cash equivalents|11,348,160|2,023,772|
|Trade and other receivables|1,323,133|2,278,319|
|Other financial assets|116,007|85,778|
|Non-Current Assets|
|Exploration and evaluation assets|58,861,246|34,124,907|
|Current Liabilities|
|Trade and other payables|17,906,641|27,994,622|

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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|2015|2014|
|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|
|First Australian Resources, Inc.|USA|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|
|Petrole Investments Group Pty Ltd|Mauritius|100|100|
|Arawak Oil & Gas Limited|[ (iv)]|British Virgin Islands|-|100|
|Meridian Minerals Limited|Mauritius|100|100|
|FAR Mauritius 1 Pty Ltd|Mauritius|100|-|
|FAR Mauritius 2 Pty Ltd|Mauritius|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.
(iv) Arawak Oil & Gas Limited was a redundant entity and de-registered. No profit or loss was recorded on de-registration during the year.

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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 2015|31 Dec 2014|
|Statement of profit or loss and other comprehensive income|AU$|AU$|
|Interest income|286,774|629,008|
|-|
|Gain on recovery of back costs|688,622|
|Depreciation and amortisation expense|(44,327)|(21,741)|
|Impairment of intercompany loans and investments|(1,785,162)|(1,155,316)|
|Exploration expense|(15,032,502|(6,210,627)|
|Finance costs|(639)|
|Administration expense|(563,654)|(538,264)|
|Employee benefits expense|(3,102,003)|(1,648,717)|
|Consulting expense|(539,255)|(528,411)|
|Foreign exchange gain|1,338,022|2,422,453|
|Other expenses|(238,311)|(172,170)|
|Loss before income tax|(19,680,418)|(6,535,802)|
|Income tax expense|
|Loss for the year|(19,680,418)|(6,535,802)|
|Other comprehensive loss|
|Items that may be reclassified subsequently to profit or loss|
|Exchange differences arising on translation of foreign operations|729,715|(406,039)|
|Total comprehensive loss|(18,950,703)|(6,941,841)|

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2015 FAR Annual Report 55

Notes to the Financial Statements

For the financial year ended 31 December 2015

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Statement of Financial Positon	31 Dec 2015 AU$ 31 Dec 2014 AU$
CURRENT ASSETS
Cash and cash equivalents	60,469,881 66,833,831
Receivables	1,617,775 590,913
Other fnancial assets	142,383 2,334,779
Other
Total Current Assets	62,230,039 69,759,523
NON CURRENT ASSETS
Trade and other receivables	108,130 100,649
Other fnancial assets	103 -
Property, plant and equipment	346,186 153,410
Exploraton and evaluaton assets	58,404,093 33,722,953
Total Non-Current Assets	58,858,512 33,977,012
TOTAL ASSETS	121,088,551 103,736,535
CURRENT LIABILITIES
Trade and other payables	18,684,866 28,420,122
Provisions	696,155 558,396
Other current liabilites
Total Current Liabilites	19,381,021 28,978,518
NON-CURRENT LIABILITIES
Provisions	89,819 60,382
Total Non-Current Liabilites	89,819 60,382
TOTAL LIABILITIES	19,470,840 29,038,900
NET ASSETS	101,617,711 74,697,635
EQUITY
Issued capital	237,806,280 195,770,161
Reserves	9,007,355 5,114,476
Accumulated losses	(145,195,924) (126,187,002)
TOTAL EQUITY Accumulated Losses	101,617,711 74,697,635
	31 Dec 2015 AU$ 31 Dec 2014 AU$
Balance at beginning of fnancial year	(126,187,002) (119,651,200)
Transfer from convertble notes reserve	671,496
Net loss	(19,680,418) (6,535,802)
Balance at end of fnancial year	(145,195,924) (126,187,002)

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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 2015|31 Dec 2014|
|AU$|AU$|
|Cash and cash equivalents|49,322,737|65,201,525|
|Cash and cash equivalents held in joint operations|11,348,160|2,023,772|
|60,670,897|67,225,297|

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(b) Financing facilities

The Group had no external borrowings at 31 December 2015. 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 2015.

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

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||||
|---|---|---|
|31 Dec 2015|31 Dec 2014|
|AU$|AU$|
|Loss for the year|(19,620,114)|(6,937,168)|
|Depreciation and amortisation of non-current assets|44,327|49,587|
|Unrealised Foreign exchange gain|(1,329,412)|(2,235,328)|
|-|
|Equity settled share-based payments|1,110,667|
|Interest income|(287,088)|(629,293)|
|-|
|(Gain) / loss on sale of exploration and evaluation assets|(688,622)|
|-|-|
|Loss on sale of property, plant and equipment|
|(Increase) / decrease in assets:|
|Trade and other receivables|(183,138)|(124,972)|
|Inventories|-|81,236|
|-|
|Other financial assets|(21,329)|
|Other current assets|(54,697)|(887,983)|
|Increase / (decrease) in liabilities:|
|Trade and other payables|1,054,801|(214,051)|
|Provisions|167,197|280,416|
|Net cash used in operating activities|(19,118,786)|(11,306,178)|

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2015 FAR Annual Report 57

Notes to the Financial Statements

For the financial year ended 31 December 2015

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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 2015 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 2015|31 Dec 2014|
|AU$|AU$|
|Financial assets|
|Cash and cash equivalents|60,670,897|67,225,297|
|Trade and other receivables – current and non-current|1,673,542|508,422|
|Other financial assets – current and non-current|116,007|85,778|
|Total Financial assets|62,460,446|67,819,497|
|Financial liabilities|
|Trade and other payables|18,761,407|28,528,748|

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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 $4,302,928.

(e) Commodity price risk management

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

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(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.

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
2015 % AU$ AU$ AU$ AU$ AU$ AU$
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
2014
Financial assets:
- - - - -
Non-interest bearing 31,484,655 31,484,655
Variable interest rate 2.03 2,649,942 - - - - 2,649,942
Fixed interest rate 3.17 23,600,000 10,084,900 - - - 33,684,900
- - -
57,734,597 10,084,900 67,819,497
Financial liabilities:
- -
Non-interest bearing 28,462,534 45,779 20,381 28,528,694
-
28,462,534 45,779 20,381 28,528,694
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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 $28,667.

(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 (2014: net fair value).

2015 FAR Annual Report 59

Notes to the Financial Statements For the financial year ended 31 December 2015

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22. SHARE-BASED PAYMENTS

(a) Employee share option plan

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

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||||||||
|---|---|---|---|---|---|---|
|Option series|Grant|Fair value at|Exercise|Expiry|Number|Vesting|
|date|grant date|price|date|date|
|Series 7|31 May 2012|2.1 cents|6.0 cents|30 Jun 2015|52,500,000|Vests at the date of grant|
|Series 8|23 Jul 2012|2.9 cents|6.0 cents|23 Jul 2015|10,000,000|Vests at the date of grant|
|Series 9|21 Aug 2012|2.5 cents|6.0 cents|30 Jun 2015|6,000,000|Vests at the date of grant|
|Series 10|27 May 2013|1.6 cents|4.4 cents|27 May 2016|62,000,000|Vests at the date of grant|
|Series 11|1 Jul 2015|4.9 cents|10.0 cents|1 Jun 2018|68,000,000|Vests on the announcement|
|to the effect of potential|
|economic viability of a future|
|development project by|
|the Senegal joint venture|
|Operator before 1 June 2018|

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(b) Fair value of share options granted in the year

The weighted average fair value of the share options granted during the financial year is 4.9 cents. Options were priced using the Black Scholes pricing model. Where relevant the expected useful life used in the model has been adjusted based on management’s best estimates for the effects of non-transferability, exercise restrictions (including the probability of meeting market conditions attached to the option), and behavioural considerations. Expected volatility is based on the historical share price volatility over the past 1 year which is considerably more conservative than over the past 3 years based on the current macro market conditions.

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|||
|---|---|
|Inputs into the model|Option Series 11|
|Grant date share price|8.7 cents|
|Exercise price|10.0 cents|
|Expected volatility|95%|
|Option life|2.92 years|
|-|
|Dividend yield|
|Risk-free interest rate|2.00%|

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(c) Movement in share options during the year

The following reconciles the share options outstanding at the beginning and end of the financial year:

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||||||
|---|---|---|---|---|
|31 Dec 2015|31 Dec 2014|
|Number of|Weighted|Number of|Weighted|
|options|average|options|average|
|exercise price|exercise price|
|Balance at beginning of the financial year|128,500,000|5.2 cents|132,000,000|5.4 cents|
|Granted during the financial year|68,000,000|10.0 cents|-|-|
|-|-|-|-|
|Forfeited during the year|
|Exercised during the year|(66,500,000)|6.0 cents|(2,000,000)|6.0 cents|
|Expired during the financial year|-|-|(1,500,000)|18.0 cents|
|Balance at the end of the financial year|130,000,000|7.3 cents|128,500,000|5.2 cents|
|Exercisable at end of year|130,000,000|7.3 cents|128,500,000|5.2 cents|

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(d) Share options exercised during the year

The following share options were exercised during the year:

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||||||
|---|---|---|---|---|
|Option series|Grant date|Number|Exercise date|Share price at|
|exercised|exercise date|
|Series 7|31 May 2012|250,000|4 Feb 2015|8.87 cents|
|Series 7|31 May 2012|500,000|8 Apr 2015|9.56 cents|
|Series 7|31 May 2012|750,000|21 Apr 2015|9.86 cents|
|Series 7|31 May 2012|1,000,000|20 May 2015|10.45 cents|
|Series 7|31 May 2012|1,000,000|3 Jun 2015|9.36 cents|
|Series 7|31 May 2012|47,000,000|24 Jun 2015|7.87 cents|
|Series 9|21 Aug 2012|6,000,000|24 Jun 2015|7.87 cents|
|Series 8|23 Jul 2012|10,000,000|15 Jul 2015|7.97 cents|

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(e) Share options outstanding at the end of the year

The share options outstanding at the end of the year had a weighted average exercise price of 7.3 cents (2014: 5.2 cents) and a weighted average remaining contractual life of 532 days (2014: 343 days).

2015 FAR Annual Report 61

Notes to the Financial Statements

For the financial year ended 31 December 2015

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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 2015|31 Dec 2014|
|AU$|AU$|
|Short-term employee benefits|2,370,418|1,860,803|
|Post-employment benefits|126,800|82,500|
|-|
|Share-based payment|767,668|
|Other long-term benefits|23,955|58,584|
|Total|3,288,841|2,001,887|

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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 9 March 2016, FAR announced successful completion of the SNE-3 appraisal well. This well demonstrated the ability of SNE field upper reservoir units to flow at commercially viable rates and make a material contribution to oil volumes. Two drill stem tests (DST) have confirmed the deliverability of the upper reservoir units. A gross 15m 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 5.5m zone that was combined with the first flow has produced at a stabilised flow rate of 4,500 bopd (56/64” choke). Flow rates were equipment constrained, exceeded FAR pre-drill expectations, and have confirmed excellent reservoir quality and correlation between SNE-1, SNE-2 and SNE-3. SNE-3 results are expected to support a further upgrade of SNE field resource estimates.

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.

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26. REMUNERATION OF AUDITORS

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||||
|---|---|---|
|31 Dec 2015|31 Dec 2014|
|AU$|AU$|
|Auditor of the Parent Entity:|
|Audit or review of the financial report|67,980|73,595|
|Tax services|-|21,000|
|67,980|94,595|

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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 2015|31 Dec 2014|
|AU$|AU$|
|Assets|
|Current assets|62,230,039|69,759,522|
|Non-current assets|58,858,514|33,977,115|
|Total Assets|121,088,553|103,736,637|
|Liabilities|
|Current liabilities|19,381,021|28,978,517|
|Non-current liabilities|89,819|60,382|
|Total Liabilities|19,470,840|29,038,899|
|Equity|
|Issued Capital|237,806,280|195,770,262|
|Reserves|
|– Option reserve and equity component on convertible notes|5,955,222|5,516,051|
|– Foreign currency translation reserve|3,052,132|(401,575)|
|Accumulated losses|(145,195,921)|(126,187,000)|
|Total Equity|101,617,713|74,697,738|

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(b) Financial performance

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||||
|---|---|---|
|Year ended|Year ended|
|31 Dec 2015|31 Dec 2014|
|AU$|AU$|
|Loss for the year|(19,680,417)|(6,535,802)|
|-|
|Transfer from convertible notes reserve|671,496|
|Other comprehensive income/loss|3,453,707|(406,039)|
|Total comprehensive loss|(15,555,214)|(6,941,841)|

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2015 FAR Annual Report 63

Notes to the Financial Statements

For the financial year ended 31 December 2015

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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 there are no guarantees entered into by the Parent Entity in relation to the debts of its subsidiaries (2014: $nil).

(d) Contingent liabilities of the parent entity

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||||
|---|---|---|
|31 Dec 2015|31 Dec 2014|
|AU$|AU$|
|Guinea-Bissau – contingent payment from future production|17,793,594|15,849,793|
|Guinea-Bissau – contingent withholding tax liability|777,185|685,067|
|-|
|Senegal – performance bond|
|18,570,779|16,534,860|

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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 2015|31 Dec 2014|
|AU$|AU$|
|Exploration and evaluation assets|
|Not longer than 1 year|36,792,291|1,605,936|
|-|
|Longer than 1 year and not longer than 5 years|44,196,263|
|80,988,554|1,605,936|

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

Refer to Note 16 for further details.

Supplementary Information

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Pursuant to the Listing requirements of the Australian Securities Exchange

Number of holders of equity securities

Ordinary Shares

At 23 March 2016, the issued capital comprised of 3,693,650,099 ordinary shares held by 11,230 holders.

Unlisted Options

At 17 March 2016, there were 130,000,000 unlisted options, of various exercise prices and expiry dates, held by 12 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.

Spread details as at 17 March 2016 – Ordinary Shares

Spread details as at 17 March 2016 – Ordinary Shares
Number of Holders	Number of Units % of Total Issued Capital
1 - 1,000 590	251,521 0.700
1,001 - 5,000 568	1,883,245 0.051
5,001 - 10,000 945	7,899,518 0.214
10,001 - 100,000 5,616	246,915,477 6.685
100,001 and over 3,511	3,436,700,338 93.043
Total 11,230	3,693,650,099 100.000
Holding less than a marketable parcel 1,021

Substantial Shareholder

Substantal Shareholder
Number of shares Percentage
Farjoy Pty Ltd 404,963,236 10.964
Top Twenty Shareholders as at 17 March 2016 Number of shares Percentage
Farjoy Pty Ltd 404,963,236 10.964
J P Morgan Nominees Australia Limited 318,312,944 8.618
HSBC Custody Nominees (Australia) Limited 117,293,271 3.176
Citcorp Nominees Pty Limited 107,334,199 2.906
Natonal Nominees Limited 95,593,825 2.588
Mr Oliver Lennox-King 75,647,869 2.048
Toad Facilites Pty Ltd 61,411,765 1.663
BNP Paribas Noms Pty Ltd 39,779,430 1.077
Fountain Oaks Pty Ltd 34,200,366 0.926
CS Fourth Nominees Pty Limited 26,389,214 0.714
Floteck Consultants Limited 26,000,000 0.704
Brispot Nominees Pty Ltd 20,995,732 0.568
Mr John Daniel Powell 20,046,777 0.543
Merrill Lynch (Australia) Nominees Pty Limited 18,539,517 0.502
Mr Philip Alan Kenneth Naylor 15,000,000 0.406
N & P Superannuaton Pty Limited 14,677,441 0.397
Mr Peter John Brunton 11,808,000 0.320
Almeranka Superannuaton Pty Ltd 11,331,621 0.307
Citcorp Nominees Pty Limited 10,766,048 0.291
Mr Colin Paul Millar 10,240,800 0.277
1,440,332,055 38.995

2015 FAR Annual Report 65

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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

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

Bank of the West 600 17th Street, Suite 1500 Denver Colorado 80202 United States of America

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

Peter Thiessen

SOLICITORS

REGISTERED OFFICE & PRINCIPAL PLACE OF BUSINESS

Level 17, 530 Collins Street Melbourne Victoria 3000 Australia

ADR DEPOSITARY

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

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

AUDITORS

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

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

Deloitte Touche Tohmatsu 550 Bourke Street Melbourne Victoria 3000 Australia

This document is intended to be distributed electronically. Please consider the environment before you print.

Design: Pauline Mosley www.paulinemosley.com Athena images courtesy of Ocean Rig 3D seismic vessel image images courtesy of Polarcus Limited

==> picture [543 x 745] intentionally omitted <==

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

AI assistant

FAR LIMITED — Annual Report 2015

64899_rns_2016-03-21_82297efa-2142-46a5-8d81-8b5193c4e0c5.pdf

Amendment - Annual Report to Shareholders

A close look at FAR

Fellow Shareholders,

Significant work still lies ahead.

SNE contingent resource upgraded

Operations Review

OFFSHORE WEST AFRICA

Proving deep water elephants offshore Senegal

SENEGAL

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

Operations Review

THREE WELL DRILLING PROGRAM

OCEAN RIG ATHENA SELECTED

SNE-2 WELL RESULT

SNE OIL FIELD CONTINGENT RESOURCES UPGRADE

SNE OIL FIELD CONTINGENT RESOURCES UPGRADE

DJIFFERE BLOCK OPTION

3D SEISMIC SURVEYS

EXPLORATION POTENTIAL

GUINEA-BISSAU

EAST AFRICA

Large equity positions in a fast emerging oil and gas margin

KENYA: Lamu Blocks

Block L6

Operations Review

Block L9

Operator: Ophir Energy PLC (‘‘Ophir Energy’)

AUSTRALIA

Surrounded by proven petroleum systems

WESTERN AUSTRALIA

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

CORPORATE ACTIVITY

EXPLORATION ASSETS

*Disclaimers

Charters

Policies

INFORMATION ABOUT THE DIRECTORS

Nicholas James Limb – Non-Executive Chairman

Bsc (Hons) MAusIMM (appointed 28 November 2011)

Catherine Margaret Norman – Managing Director

Charles Lee Cavness – Non-Executive Director (resigned 15 May 2015)

Albert Edward Brindal – Non-Executive Director

BCom, MBA, FCPA (appointed 19 December 2007)

Reginald Nelson – Non-Executive Director

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

DIRECTORSHIPS OF OTHER LISTED COMPANIES

DIRECTORS’ SHAREHOLDINGS

REMUNERATION OF KEY MANAGEMENT PERSONNEL

SHARE OPTIONS GRANTED TO DIRECTORS AND SENIOR MANAGEMENT

COMPANY SECRETARY

Peter Anthony Thiessen

PRINCIPAL ACTIVITIES

OPERATING RESULTS

DIVIDENDS

REVIEW OF OPERATIONS

Financial position

Business strategy and prospects

MATERIAL BUSINESS RISKS

TECHNICAL AND OPERATIONAL RISKS

Exploration

Other operational risks

JOINT OPERATION RISK

GOVERNMENT AND REGULATOR RISK

SOVEREIGN RISK

ENVIRONMENTAL RISKS

CHANGES IN STATE OF AFFAIRS

Kenya L6

Kenya L9

Guinea-Bissau

Western Australia

Subsequent events

LIKELY DEVELOPMENTS

INDEMNIFICATION OF OFFICERS AND AUDITORS

DIRECTORS’ MEETINGS

ENVIRONMENTAL REGULATIONS

PROCEEDINGS ON BEHALF OF THE COMPANY

NON-AUDIT SERVICES

FAR LIMITED Annual Report 2015