FAR LIMITED — Interim / Quarterly Report 2016

Apr 28, 2016

==> picture [595 x 172] intentionally omitted <==

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

01 January – 31 March 2016
----- End of picture text -----

Highlights

• Appraisal drilling program continued offshore Senegal

• Successful completion of two SNE field appraisal wells: SNE-2, SNE-3

• Significant upgrade to SNE field size

• SNE-2 and SNE-3 flowed oil at commercially viable rates

• Spud of BEL-1, the third in the firm three well program

• Annual Report to shareholders released

• Cash at end of quarter $31.7M, no debt

• Successful equity raising completed after end of quarter

Projects update

Offshore Senegal

During the period, FAR and its JV partners successfully continued the evaluation of the SNE oil discovery offshore Senegal with the successful drilling of the SNE-2, SNE-3 and BEL-1 appraisal wells (note that the BEL-1 well was spudded during the period and results announced following the end of the quarter).

Prior to including the results of these appraisal wells into a reassessment of the contingent resource estimates for the SNE field, FAR commissioned RISC Operations Pty Ltd (“RISC”) to prepare an Independent Resources Report for FAR’s SNE oil field offshore Senegal. The report was prepared incorporating data available from wells SNE1 and FAN-1 and reprocessed 3D seismic (Refer: FAR ASX announcement 8 February 2016).

==> picture [248 x 233] intentionally omitted <==

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

Figure 1: Location of the SNE Field offshore Senegal
----- End of picture text -----

The SNE contingent resources set out in RISC’s Independent Resource Report represented a material increase to the estimates previously reported by FAR shortly after the discovery of the field in late 2014 (Refer: FAR ASX announcement 10 November 2014) with the SNE field 2C contingent resource increasing by 42% to 468 mmbbls (100% basis, recoverable).

Table 1 below sets out the SNE field oil contingent resource estimates included in RISC’s report.

Table 1. Summary of Oil Contingent Resources (MMstb)

	Gross	Gross	Gross	Net Attributable	Net Attributable	Net Attributable
	1C	2C	3C	1C	2C	3C
SNE Discovery	240	468	940	36	70	141

1. Gross are 100% of the resources attributable to the licence. 2. Net attributable are reported on the basis of FAR’s current working interest share of 15%. Petrosen has an option to increase its working interest through the exploitation phase which would reduce FAR’s working interest to 13.7%.

3. The contingent estimates are not adjusted to reflect the Production Sharing Contract entitlement on net economic interest basis.

SNE-2 Well results

On 4 January 2016, FAR announced the results of the successful SNE-2 appraisal well and flow test. It 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 potential to flow oil at commercially viable rates:

• A drill stem test (DST) of the lower principal oil reservoir unit over a 12m interval (~11.5m net) flowed oil at a maximum stabilised constrained rate of ~8,000 bopd on a 48/64” choke. The interpreted unconstrained flow rate of this interval 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 15m interval (~3.5m net) flowed oil at a maximum rate of ~1,000 bopd on a 24/64” choke. The flow from this interval was unstable due to the 4.5” DST tubing, however, this result confirms the potential of the “heterolithic” Figure 2: FAR well locations on the SNE Field reservoir units to produce at commercially 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.

• Gas-Oil and Oil-Water depths have been confirmed, showing a similar oil-down-to and oil-up-to depth at SNE-2 of 103m gross (SNE-1 is 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 216m of continuous core (100% recovery) was recovered across the entire SNE field reservoir interval.

SNE-3 Well results

SNE-3 was the second SNE oil field appraisal well to be drilled in the appraisal program. It is located in the Senegal Sangomar Deep Offshore Block approximately 3km south of the initial SNE-1 discovery well (refer Figure 2).

SNE-3 was initially “top hole” drilled to a depth of 1,755m by the Ocean Rig Athena prior to the spud of the SNE-2 well ( Refer: FAR ASX announcement 2 November 2015 ). After completion of SNE-2, the Ocean Rig Athena returned to the SNE-3 location and began re-drilling the well on 18 January 2016.

• Refer to Cautionary Statement in this report (page 9) relating to estimates of prospective resources

Page 2

SNE-3 began its coring program on 26 January 2016 and reached its planned total depth of 2,807m TVD on 31 January 2016.

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

The SNE-3 well has been successfully completed following drilling, coring, logging and drillstem testing (DST). The tests have confirmed excellent reservoir quality and correlation between the SNE-1, SNE-2 and SNE-3 wells.

==> picture [289 x 198] intentionally omitted <==

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

561
468
330
154
Figure 3: Growth of the SNE Field over time
----- End of picture text -----

Flow rates recorded were equipment constrained and exceeded FAR pre-drill expectations with initial results as follows:

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

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

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

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

• Initial data confirms the same 32 degree API oil quality as seen in SNE-1 and SNE-2.

• Reservoir units were intersected shallower to prognosis (higher than expected on the structure) suggesting the southern flank of the oil field is more extensive than initially prognosed and will extend further to the south than previously mapped.

SNE Appraisal program and further increase in contingent resources

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

Analysis of the SNE-1 well data showed:

• 95m gross oil bearing column with a gas cap.

• Excellent Albian reservoir sands with net oil pay of 36m.

• High quality oil of 32 degrees API from samples of gas, oil and water recovered to surface.

• FAR’s estimates of the gross contingent recoverable resource (following the RISC Independent Resources Report and refer: FAR ASX announcement 8 February 2016 ) range from a 1C of 240 mmbbls, 2C, 468 mmbbls to a 3C of 940 mmbbls (net to FAR; 1C: 36 mmbbls, 2C: 70 mmbbls, 3C: 141 mmbbls)*.

Key aims of the SNE appraisal drilling program are to progress towards proving a minimum economic field size for the SNE discovery, which FAR estimates to be approximately 200 million barrels of recoverable oil, and determining flow rates and connectivity of the reservoirs aross the field for the planning of a future development. Flow test results at both SNE-2 and SNE-3 have demonstrated that multiple reservoirs within the SNE field are capable of flowing at commercially viable flow rates and hence, in FAR’s view, this objective of the current three well appraisal drilling program has been met.

• Refer to Cautionary Statement in this report (page 9) relating to estimates of prospective resources

Page 3

FAR continues to review the contingent resource estimates for the SNE field as the drilling program progresses and more data is obtained. In events following the end of the quarter, FAR released a further upgrade of the contingent resources which were again independently assessed by RISC ( Refer: FAR ASX announcement 13 April 2016 ). Figure 3 (shown on page 4) shows the growth of the SNE field from pre-drill estimate, discovery estimate, pre-appraisal estimate and post SNE-2 and SNE3 appraisal wells. Highlights from the update of contingent resources are listed on the following page:

• SNE oil field 2C contingent resource increased by 20% to 561 mmbbls gross.

• Update follows results of SNE-2 and SNE-3 appraisal wells and final reprocessed 3D seismic data.

• Further update expected after BEL-1 and SNE-4 well results.

• The SNE oil field Minimum Economic Field Size (“MEFS”) is estimated by FAR to be approximately 200 mmbbls gross.

The third firm exploration well in the drilling campaign (BEL-1 – see Figure 2 for location) was spudded during the quarter ( Refer: FAR ASX announcement 15 March 2016 ) and was drilled on the Bellatrix Prospect that sits above the SNE field. The results from the BEL-1 were announced following the end of the quarter.

Initial exploration results from the successful BEL-1 well include:

• Gas discovered in the Bellatrix exploration prospect in a series of stacked sandstones

• Two good quality gas bearing sandstone reservoirs in lower zones (8m net) with upper zones interpreted to be tight

• No water-bearing units encountered

• Potential for down-dip oil with extensive structural closure

• Buried Hills play type confirmed and de-risked for future exploration

The BEL-1 well also provided significant and highly positive appraisal information about the SNE field, which lies below Bellatrix.

BEL-1 well SNE appraisal results include:

• Gas-Oil and Oil-Water depths indicate an oil column of approximately 100m gross at BEL-1, similar to gross oil columns seen in the SNE-1, SNE-2 and SNE-3 appraisal wells.

• Confirms the extension of reservoirs and oil column in the northern flank of the SNE field.

• Good quality reservoir sands within the reservoir units.

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

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

• Initial measurements show similar oil quality as seen in SNE-1, SNE-2 and SNE-3.

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

The BEL-1 well was the first well to target the shallow Buried Hills exploration play, just one of multiple exploration play types identified within FAR’s offshore Senegal blocks.

The BEL-1 well result confirms the Buried Hills play type and the presence of good reservoirs and regionally extensive seals. These shallower reservoirs were also encountered in SNE-3, 9kms to the south (as seen in Figure 2). With the discovery of gas in good shallow reservoirs, the BEL-1 well results along with the latest 3D seismic (2015 survey as seen in Figure 1), will be incorporated into the assessment for potential down-dip oil in shallower reservoirs across FAR’s Senegal blocks including the Djiffere permit.

The BEL-1 well was located in 1,031m water depth and was drilled to a total depth of 2,767m TVD. The well was drilled, cored and logged as planned and completed ahead of schedule.

The successful appraisal well results from the BEL-1 well are expected to support another revision of FAR’s resource estimates for the SNE field.

• Refer to Cautionary Statement in this report (page 9) relating to estimates of prospective resources

Page 4

The results from the BEL-1 well and the core analysis from all appraisal wells drilled are expected to contribute to a further review of contingent resources for the SNE Field.

Fourth appraisal well to be drilled

Given the success of the ongoing appraisal programme, the joint venture has agreed that the Ocean Rig Athena will drill SNE-4, located 5km south-east of the SNE-1 discovery well, to appraise the eastern extent of the field, where it is aiming to confirm the nature of the upper reservoirs in the oil zone (the location of SNE-4 is shown in Figure 2). The rig has resumed drilling after completing the top hole and scheduled maintenance to the blow out preventer. Results of the SNE-4 well are expected to be released before the end of May.

3D Seismic survey

A 2,400km[2] 3D seismic survey over the Sangomar and Rufisque blocks was completed at the end of 2015 and processing of this data is ongoing with final products expected in Q3 2016. The aim of this program is to close eastern boundaries of existing prospects and leads and define a prospect inventory to the north and east. A map showing the seismic survey is shown in Figure 4. Final processed products for this survey are expected in Q3 2016.

A 2,400m3D seismic survey over te Sangomar and Rufisque blocks was completed at the end of 2015 and processing of this data is ongoing with final products expected in Q3 2016. The aim of this program is to close eastern boundaries of existing prospects and leads and define a prospect inventory to the north and east. A map showing the seismic survey is shown in Figure 4. Final processed products for this survey are expected in Q3 2016. Rufisque, Sangomar, Sangomar Deep Working Interest FAR 15% Cairn Energy 40% Operator ConocoPhillips 35% Petrosen 10% Figure 4: Location of 3D seismic database	A 2,400m3D seismic survey over te Sangomar and Rufisque blocks was completed at the end of 2015 and processing of this data is ongoing with final products expected in Q3 2016. The aim of this program is to close eastern boundaries of existing prospects and leads and define a prospect inventory to the north and east. A map showing the seismic survey is shown in Figure 4. Final processed products for this survey are expected in Q3 2016. Rufisque, Sangomar, Sangomar Deep Working Interest FAR 15% Cairn Energy 40% Operator ConocoPhillips 35% Petrosen 10% Figure 4: Location of 3D seismic database
Rufisque, Sangomar, Sangomar Deep	Working Interest
FAR	15%
Cairn Energy	40% Operator
ConocoPhillips	35%
Petrosen	10%

Djiffere Block option

In 2015, FAR entered into a farm in option agreement with a subsidiary of Trace Atlantic Oil Ltd (“Trace”) for the Djiffere block offshore Senegal (see Figure 4). 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 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 of 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.

FAR acquired a 3D seismic survey in the western part of the Djiffere block as an extension to the larger RSSD seismic survey. The Djiffere survey, in combination with other seismic data will provide 400km2 of 3D coverage over the block and will evaluate the shelf trend potential therein. The survey was completed in November and final processed products are expected to be delivered in Q3 2016.

• Refer to Cautionary Statement in this report (page 9) relating to estimates of prospective resources

Page 5

Offshore Guinea-Bissau

In late April 2015, the Government of GuineaBissau approved a 2 year extension to the current exploration term. The extension period begins on 26 November 2015 and concludes on 25 November 2017.

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 interpreted.

The joint venture expects to provide an update on the prospects offshore Guinea-Bissau in the coming months.

==> picture [230 x 238] intentionally omitted <==

Figure 5: Location of FAR blocks offshore Guinea-Bissau

Block 2, Block 4A, Block 5A	Paying Interest
FAR	21.43%
Svenska	78.57% Operator

Kenya

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

Under the terms of the Joint Operating Agreement, FAR’s partner in the L6 Joint Venture (Pancontinental Oil and Gas) was issued with default notices for non-payment of two cash calls in February 2015. FAR and Pancontinental have been in discussions regarding the matter and aim to resolve the default as soon as possible.

Kenya Block L6	Paying Interest Onshore	Paying Interest Offshore
FAR	24% Operator(i)	60% Operator
Pancontinental Oil and Gas	16%	40%
Milio Group	60%(i)

(i) Subject to the completion of the farm-out agreement with Milio. (Refer to (i) of Project table on page 10 for further information)

Kenya Block L9	Paying Interest
FAR	30%
Ophir Energy	70% Operator

• Refer to Cautionary Statement in this report (page 9) relating to estimates of prospective resources

Page 6

==> picture [596 x 84] intentionally omitted <==

Australia

FAR has participated in a speculative 3D seismic survey that commenced in Q2 2015 covering WA-457-P and a portion of WA-458-P. FAR is planning to acquire 3D seismic over the remainder of the WA-458-P block. The seismic contractor, CGG, has now secured environmental approvals for the data acquisition over the Glomar Shoals.

WA-457-P, WA-458-P	Paying Interest
FAR	100% Operator

==> picture [168 x 131] intentionally omitted <==

Figure 6: Location of WA-457-P and WA-458-P

Management comment

FAR Ltd Managing Director, Cath Norman said, “During this quarter and up to the date of writing this report, the Senegal joint venture has successfully completed the first of the three wells to be drilled as part of the Senegal 2015/16 work program to evaluate the SNE field. The results have established that the SNE field is world class and has the potential to flow at commercially viable rates in both the upper and lower reservoir sands that have been tested to date. As the appraisal program has progressed, we have stepped out and drilled off the crest of the SNE structure (SNE-3 and BEL-1) to assess the size of the field and encounter the upper sands, previously in the gas cap, in the oil leg. Whilst we have had success in achieving both objectives, the drilling has proven that the field is getting broader and larger and hence not all of our potentially high quality reservoir sands have been encountered in oil. As a result, the field size is growing (currently it has a footprint of approximately 330km[2] ) and in addition, the JV elected to drill a further step out appraisal well, SNE-4, to encounter additional reservoir sands in oil.

Early in the quarter, FAR released a pre-appraisal upgrade to the contingent resource estimates for the SNE Field and contracted RISC of Perth to carry out an independent audit of the work done. Following the drilling of the SNE-1 and the FAN-1 wells, the depth and rock property information collected were integrated with the seismic data set to produce a more robust reservoir model to that used pre-drill. As a result, the SNE field was remapped and the volume of reservoir rock in the field increased significantly leading to a contingent resource estimates increase. Notably, the 2C estimate increased by 42% to 468mmbbls (from 330mmbbls on a gross basis).

Following the end of the quarter and after integrating the results of the first two successful appraisal wells (SNE-2 and SNE-3), FAR upgraded the assessment of contingent resources for the SNE Field. RISC were again used to carry out the independent review and as a result the current range of contingent resources for the field is between 277mmbbls (1C) to 1,071mmbbls (3C) with the 2C estimate increasing by 20% to 561mmbbls. It is FAR’s opinion that this upgrade, together with the wonderful flow test results to date demonstrate that two of the key objectives of the appraisal program have been achieved, that is: firstly proving the number of barrels in the field to be greater than the estimated minimum economic threshold and secondly the deliverability of those barrels. Understanding the connectivity of our reservoirs across the field now remains as a key objective of the appraisal program going forward. This information will allow us to determine the number of development wells needed and hence better understand the capital expenditure and commercial viability of the field development.

The growth of the SNE field from a pre-drill P50 estimate of 150mmbbls to a 2C estimate today of 561mmbbls has been achieved in a remarkably short period (around 16 months) and it is a tribute to the JV and the Government of Senegal that the evaluation of the field has progressed so swiftly. FAR

• Refer to Cautionary Statement in this report (page 9) relating to estimates of prospective resources

Page 7

is currently integrating the BEL-1 results into our evaluation of the SNE field and this, combined with the addition of the core analysis and results of the SNE-4 well will culminate in a further review and independent audit by RISC in the coming months.

FAR finished the March quarter with a cash position of approximately A$32 million and no debt. Following the end of the quarter, we successfully raised A$60 million via a private placement to institutions and sophisticated investors. Approximately A$47 million dollars equating to FAR’s 15% placement capacity has been received to date and the balance is subject to shareholder approval at an EGM to be held on Tuesday 31 May 2016, following the AGM to be held on Friday 13[th] May 2016.. The capital raise was essential for FAR to continue to participate in the work program going forward which may include the drilling of two more optional wells in the current drilling campaign with the Ocean Rig Athena. The decision to continue drilling will be made by the JV in mid Q2. FAR strongly supports extending the current drilling campaign to enable the JV to make a statement about the field commerciality later this year and to ensure that the goals of the 3 year evaluation program under the PSC are met. It is important to note that the Athena and the drilling management team have been performing extremely well through this drilling campaign. The non-productive rig time (NPT) has been improving with each well drilled and was less than 2% on the BEL-1 well.

FAR is very pleased to have strengthened the register with the addition of new, large institutional shareholders and the success of the capital raise is testimony to the high quality of the Senegal asset and the significant opportunity we have to grow shareholder wealth in the coming months.

As stated in the last quarterly report, FAR is still amid a very exciting drilling program and one that so far is proving the SNE field to be revealing itself as a truly world class asset. We currently look forward to SNE-4 well results and our AGM on 13 May 2016. This year marks the tenth anniversary of FAR’s participation in Senegal and we look forward to seeing our shareholders at the meeting. As well as our team based here in Australia, Mme Gogne Seye from Dakar, Mark Jenkins (FAR’s representative from Nairobi) and Igor Effimoff (FAR’s representative in Houston who was key to FAR’s entry to Senegal in 2006) will also be in Melbourne for the meeting and will be happy to provide some insights into the Company’s activities regionally.”

For more information please contact

FAR Limited Cath Norman Managing Director T: +61 3 9618 2550 Level 17, 530 Collins Street Gordon Ramsay Executive General Manager F: +61 3 9620 5200 Melbourne VIC 3000 Australia Business Development E: info@far.com.au www.far.com.au Media enquiries Ian Howarth Collins Street Media T +61 3 9600 1979

• Refer to Cautionary Statement in this report (page 9) relating to estimates of prospective resources

Page 8

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

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

• Refer to Cautionary Statement in this report (page 9) relating to estimates of prospective resources

Page 9

==> picture [596 x 84] intentionally omitted <==

Project table

Project and Location	Tenement	Beneficial Interest	Acquired during	Disposed during the quarter
		at end of quarter	the quarter
Guinea-Bissau (offshore)	Sinapa Block 2	15.00%	–	–
	Esperanca Blocks 4A	15.00%	–	–
	& 5A
Senegal (offshore)	Rufisque,	15.00%	–	–
	Sangomar	15.00%	–	–
	Sangomar Deep	15.00%	–	–
Kenya (offshore)	Block L6	60.00%	–	–
Kenya (onshore)	Block L6	24.00%(i)	–	–
Kenya (offshore)	Block L9	30.00%(ii)	–	–
Australia (WA offshore)	WA-457-P	100.00%	–	–
	WA-458-P	100.00%	–	–

(i) Subject to the completion of the farm-out agreement with Milio. Current paying and beneficial interest is 60%. 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. (For further information, refer to Note 18 (ii) of the Notes to the Financial Statements in the FAR 2015 Annual Report).

(ii) The agreement with Ophir Energy terminated during the 2014 year and discussions have been ongoing to resolve FAR’s equity transfer.

• Refer to Cautionary Statement in this report (page 9) relating to estimates of prospective resources

Page 10

==> picture [596 x 84] intentionally omitted <==

Top 10 Shareholders

	Shareholder	Units	%
1.	FARJOY PTY LTD	441,993,391	10.37
2.	J P MORGAN NOMINEES AUSTRALIA LIMITED	426,751,484	10.01
3.	HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED	196,595,626	4.61
4.	BNP PARIBAS NOMS PTY LTD	184,673,490	4.33
5.	CITICORP NOMINEES PTY LIMITED	140,026,509	3.28
6.	NATIONAL NOMINEES LIMITED	113,996,242	2.67
7.	MR OLIVER LENNOX-KING	75,647,869	1.77
8.	TOAD FACILITIES PTY LTD	67,058,824	1.57
9.	UBS NOMINEES PTY LTD	59,968,998	1.41
10.	FOUNTAIN OAKS PTY LTD	34,200,366	0.80
	TOTAL	1,740,912,799	40.82

• Refer to Cautionary Statement in this report (page 9) relating to estimates of prospective resources

Page 11