FAR LIMITED — Interim / Quarterly Report 2017

Jul 30, 2017

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

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

01 April – 30 June 2017
----- End of picture text -----

Highlights

• 2 wells completed in the quarter to total 10 successful wells offshore Senegal

• SNE oil field appraisal well SNE-6 and deepwater exploration well FAN South-1 completed successfully, under budget and safely

• Annual General Meeting of Shareholders was held in May

• Government approval received for farm-in to 80% of blocks A2/A5 offshore The Gambia

• Cash at 30 June $91.3M

• Fully underwritten placement of shares to raise $80M completed

Projects update

Offshore Senegal

Drilling continued on the third drilling campaign offshore Senegal for the Rufisque, Sangomar and Sangomar Deep (RSSD) blocks which house the world class SNE oil field, discovered in November 2014.

The Stena DrillMAX deep water drill ship has continued to deliver excellent performance and as a result, all wells drilled in the 2017 campaign have been completed safely and under budet.

Following the successful drilling of the SNE-5 and VR-1 appraisial wells over the SNE field in the previous quarter, the final appraisal well and third well in the 2017 program, SNE-6, was drilled, logged and drill stem tested (DST).

The SNE-6 well, along with the previous successful SNE-5 well, formed part of an interference test designed to demonstrate connectivity within the Upper (400 series) Reservoirs. Pressure data from SNE-6 immediately confirmed good connectivity with SNE-5 and accordingly a short, but highly successful, DST was performed.

The DST was carried out on the Upper Reservoirs of the SNE Field, and connectivity of these reservoirs was established with the SNE-5 well and successfully addressed the remaining key objectives of the SNE field appraisal program.

The DST produced the following results:

==> picture [273 x 249] intentionally omitted <==

Figure 1: Location of the SNE-6, FAN South-1 and SNE North-1 wells

• Refer to Cautionary Statement in this report (page 7) relating to estimates of prospective and contingent resources

• The main reservoir units, pressure data and fluid contacts are in line with previous SNE appraisal wells

• Multiple samples of oil were recovered during the DST and analysis indicates oil of similar quality to previous wells

• Two DSTs were conducted within the Upper Reservoir units

• DST#1A flowed from an 11m interval at a maximum rate of ~4,700 barrels of oil per day (bopd) on a 60/64” choke. A 48 hour main flow period was performed at ~3,700 bopd on a 52/64” choke.

• For DST#1B an additional 12m zone was added and the well flowed at a maximum rate of ~5,300 bopd on a 64/64” choke, followed by a 24 hour flow at an average rate of ~4,600 bopd on a 52/64” choke.

• Pressure data from SNE-6 has confirmed that the Upper Reservoirs are connected with the same unit in SNE-5, ~1.6km away.

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

Further analysis is ongoing and work continues to determine the impact of the results on modelled reservoir architecture, recoverable resource base and forward development plan.

On completion of SNE-6, the FAN South-1 well was drilled into the South Fan prospect assessed by FAR (pre-drill) to contain 134 mmbbls of recoverable prospective resources* with an 18% chance of success (as audited by RISC, refer to announcement 7 Feb 2017). The FAN South-1 was the first pure exploration well to be drilled in the RSSD acreage since the basin opening discovery wells of FAN-1 and SNE-1 in late 2014.

The FAN South-1 well reached total depth of 5,343 metres. The well had dual targets: an Upper Cretaceous stacked multi-layer channelised turbidite fan prospect and a Lower Cretaceous base of slope turbidite fan prospect, similar to the FAN-1 oil discovery in 2014.

The well encountered hydrocarbon bearing reservoir and oil samples were obtained. Preliminary analysis indicates 31° API oil quality. Further work is being undertaken to integrate this discovery with FAN-1 to establish the commerciality of these deep water basinal resources.

FAN South-1 was drilled in a water depth of 2,175 metres and approximately 90 kilometres offshore in the Sangomar Deep Offshore Block, 30 kilometres south west of the FAN-1 exploration well. The well was the tenth well to be drilled offshore Senegal and the fourth in the 2017 drilling campaign.

The rig has now moved to the SNE North-1 location ( refer Figure 1 for well locations ) to drill into the Sirius Prospect. Sirius has been independently assessed by RISC Operations Pty Ltd (“RISC”) to contain 294 mmbbls oil on a prospective, recoverable, best estimate, gross basis* ( refer ASX announcement of 7 Feb 2017) and carry a 60% chance of geological success.

SNE North-1 is being drilled 15 km north of the SNE-1 discovery well and will be the most northerly location yet tested, on trend with the highly successful SNE field. The well is located in 900m water depth and the projected total depth of the well is 2,800 m. Operations are continuing on the well and as per other wells in this program, it is progressing ahead of budget and safely.

FAR anticipates that the results of this third drilling campaign will lead to a revision of contingent resource estimate for the SNE field and have an impact on design of the development plan in the

Page 2

• Refer to Cautionary Statement in this report (page 7) relating to estimates of prospective and contingent resources

coming months. The 1C resource is currently 348mmbbls* (gross, unrisked, ref ASX announcement 23 August 2016) compared to the minimum economic field size for the SNE field of 200mmbbls.

ConocoPhillips Senegal proposed asset sale

As reported in prior public statements by ConocoPhillips and Woodside, completion of the proposed sale of ConocoPhillips Senegal assets is subject to the rights of partners to pre-empt and Senegal Government approval.

As previously reported, FAR believes a valid pre-emptive rights notice has not been issued to the Senegal joint venture partners by ConocoPhillips, and FAR has invoked its right to resolve this dispute in accordance with the Joint Operating Agreement.

As a result of FAR’s dispute, FAR has made a request to the International Chamber of Commerce in Paris to commence arbitration proceedings to resolve the current Joint Operating Agreement dispute regarding FAR’s right to pre-empt the sale of ConocoPhillips’ interest in the Rufisque, Sangomar and Sangomar Deep Joint Venture offshore Senegal.

Rufisque, Sangomar, Sangomar Deep	Working Interest
FAR	15%
Cairn Energy	40% Operator
ConocoPhillips*	35%
Petrosen	10%

*The proposed sale to Woodside is subject to the rights of partners to pre-empt and Senegal Government approval

Djiffere Block option

No update from previous quarter.

The Gambia

During the quarter, the Government of The Republic of The Gambia in West Africa have approved the assignment of an 80% interest in offshore Blocks A2 and A5 in The Gambia to FAR from the New York and Johannesburg Stock Exchange listed ERIN Energy Corporation.

The acquisition is a significant expansion of FAR’s exploration portfolio in the rapidly emerging offshore Mauritania-Senegal-Guinea-Bissau Basin in West Africa.

The farm-in deal requires FAR to fund ERIN up to US$8 million through an exploration well expected to be drilled late in 2018.

Blocks A2 and A5 are adjacent to and on trend with FAR’s world class SNE oil field discovery and have significant exploration potential. The blocks cover an area of approximately 2,682km2 within the

==> picture [214 x 239] intentionally omitted <==

Figure 2: Location map Blocks A2 and A5 Gambia prospects and leads in relation to SNE field

Page 3

• Refer to Cautionary Statement in this report (page 7) relating to estimates of prospective and contingent resources

rapidly emerging and prolific Mauritania-Senegal-Guinea-Bissau (“MSGB”) Basin and lie approximately 30km offshore in water depths ranging from 50 to 1,200 meters (see Figure 2).

In combination, Blocks A2 and A5 have potential to contain prospective resources in excess of one billion barrels of oil (on an unrisked, best estimate, 100% basis*).

From 1,504km[2] of modern 3D seismic data acquired in the blocks, FAR has identified large prospects similar to the “shelf edge” plays FAR is targeting in Senegal (see Figure 2). FAR has mapped three potentially drillable prospects and leads.

FAR and ERIN will undertake 3D seismic reprocessing and interpretation during 2017 in order to mature prospects for drilling in late 2018.

Under the terms of the farm-in agreement, a wholly owned subsidiary of FAR, has acquired an 80% interest and Operatorship of offshore Blocks A2 and A5 from ERIN Energy Corporation. FAR will make an upfront payment of US$5.18 million and fund up to US$8.0 million of ERIN’s share of the cost of an exploration well. If ERIN’s share of the exploration well costs is less than US$8.0 million then the balance is to be paid in cash. FAR’s share of the cost of the exploration well is expected to be in the order of US$25.0 to US$30.0 million. The well when drilled will satisfy the current period work commitments for Blocks A2 and A5. FAR has issued a parent company guarantee in favour of the Government of The Gambia in accordance with the Blocks A2 and A5 licence terms. ERIN will retain a 20% working interest in Blocks A2 and A5. The well, to be funded by FAR, is to be drilled before 31 December 2018 or such later date if the current licence periods are extended. The well can be carried out in either Block A2 or Block A5.

Block 2, 5	Paying Interest
FAR	80% Operator
Erin	20%

Guinea-Bissau

No update from previous quarter

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

Page 4

• Refer to Cautionary Statement in this report (page 7) relating to estimates of prospective and contingent resources

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

Kenya

No update from previous quarter

Kenya Block L6	Paying Interest Onshore	Paying Interest Offshore
FAR	24% Operator(1)	60% Operator
PancontinentalOiland Gas	16%	40%
Milio Group	60%(1)

(1) Subject to the completion of the farm-out agreement with Milio.

Australia

No update from previous quarter

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

Management comment and events post end of the quarter

The June quarter continued the trend of high activity levels for FAR beginning with the Area of Mutual Interest (AMI) Agreement with CNOOC UK Limited and the extension of our licence agreements in Guinea Bissau with improved equity and deep-water terms.

While those agreements were the culmination of important and lengthy negotiations (and reported in detail in the previous quarter), FAR then went to the market with a significant capital raising which confirmed very strong support for the company.

FAR raised $80 million in very quick time with the issue heavily oversubscribed, in keeping with the rapidly growing international interest in the offshore Mauritania, Senegal, Guinea Bissau (MSGB) Basin centred on Senegal.

Strong support was received from existing shareholders and major new institutional investors joined FAR’s share register.

The Placement price of 8.0 cents per share represented a 4.8% discount to FAR’s last closing share price before the issue and a 3.5% discount to the volume weighted average share price for the 5 trading days ended 4 April 2017.

The funds raised are being used to support FAR’s ongoing drilling, evaluation and pre-development program offshore Senegal as well as other work such as 3D seismic reprocessing and interpretation during 2017 to mature prospects for drilling in 2018.

The capital raising has left FAR in a very strong financial position with $91.3 million in cash at quarters’ end.

FAR’s substantial drilling campaign continued in the quarter with the SNE-6 appraisal well drilled and successfully completed ahead of budget. The results in SNE-6 were significant in that they successfully addressed the remaining appraisal objective of understanding the connectivity of the Upper Reservoirs

Page 5

• Refer to Cautionary Statement in this report (page 7) relating to estimates of prospective and contingent resources

in the SNE field. By proving connectivity, the joint venture is now progressing with the pre-FEED work required to progress the development of the SNE field. We look forward to bringing progress reports late in the next quarter.

The FAN South-1 was drilled next in the program and was important as it was the first pure exploration well drilled offshore Senegal since the discoveries in 2014. The well reached total depth of 5,343m, targeting a resource of 134mmbbls oil.

The well intersected oil with a number of samples recovered to the surface. The discovery of oil in FAN South-1 yet again verifies the quality of the oil and gas generating system in our offshore Senegal permits and is another important result. However, the basinal fan play offshore Senegal, while very large, is technically complex and requires further evaluation to understand its potential commerciality.

Just prior to the end of the quarter FAR and its JV partners spudded the SNE North-1 well, located 15 km north of the SNE-1 discovery well and forming the most northerly location yet tested, in the highly successful SNE play. The well is located in 900m water depth and the projected total depth of the well is 2,800m. Operations at the well are continuing and FAR is pleased to report that, as per the other wells in the 2017 program, the well is ahead of schedule and operations continue safely.

Shortly before the end of the quarter FAR applied to the International Chamber of Commerce in Paris to commence arbitration proceedings to resolve the current Joint Operating Agreement dispute regarding FAR’s right to pre-empt the sale of ConocoPhillips’ interest in the Rufisque, Sangomar and Sangomar Deep Joint Venture offshore Senegal to Woodside Energy Ltd. At the time of writing no further update on the arbitration is available.

However FAR notes that the arbitration procedure will occur in parallel with the normal activities of the Senegal Joint Venture and is not expected to cause any delays or interruption to any of this work.

The arbitration process and cost structure is very clearly defined and is binding on the participants. It is expected to take less than a year to complete with the cost to FAR expected to be about USD1 million.

Late in the quarter one of FAR’s longest standing employees and directors, Albert Brindal retired. Mr Brindal was appointed in December 2000 as the Company Secretary and made Director in 2007. He retired as company secretary in 2013. He has made a major contribution to the success of FAR and the board wishes him well in his retirement.

At the end of the quarter and half year FAR is in a strong financial position after boosting its cash position in the previous quarter. All shares pursuant to the capital raising have now been issued. Credit Suisse, which acted as adviser in the capital raising along with RBC, continues to act as Financial Adviser to FAR.

The highly successful placement has allowed FAR to focus on continuing to build value for shareholders with the company well-funded through our 2017 commitments and likely to the final investment decision for the development of the SNE field, expected in early 2019.

Page 6

• Refer to Cautionary Statement in this report (page 7) relating to estimates of prospective and contingent resources

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

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

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

Page 7

• Refer to Cautionary Statement in this report (page 7) relating to estimates of prospective and contingent resources

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

Top 10 shareholders (as at 28 July 2017)

	Shareholder	Units	%
1.	HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED	798,076,515	14.61
2.	CITICORP NOMINEES PTY LIMITED	724,537,744	13.27
3.	FARJOY PTY LTD	514,463,236	9.42
4.	J P MORGAN NOMINEES AUSTRALIA LIMITED	349,716,001	6.40
5.	MR REX SEAGER HARBOUR	88,816,402	1.63
6.	BNP PARIBAS NOMS PTY LTD	75,671,861	1.39
7.	MR OLIVER LENNOX-KING	75,647,869	1.39
8.	NATIONAL NOMINEES LIMITED	70,862,216	1.30
9.	TOAD FACILITIES PTY LIMITED	67,528,589	1.24
10.	HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED – A/C 2	41,478,298	0.76
	TOTAL	2,806,798,731	51.39

Page 8

• Refer to Cautionary Statement in this report (page 7) relating to estimates of prospective and contingent resources

Appendix 5B Mining exploration entity and oil and gas exploration entity quarterly report

+Rule 5.5

Appendix 5B

Mining exploration entity and oil and gas exploration entity quarterly report

Introduced 01/07/96 Origin Appendix 8 Amended 01/07/97, 01/07/98, 30/09/01, 01/06/10, 17/12/10, 01/05/13, 01/09/16

Name of entity

FAR Ltd ABN Quarter ended (“current quarter”) 41 009 117 293 30 June 2017

Consolidated statement of cash flows	Current quarter $A’000	Year to date (6 months) $A’000
1. Cash flows from operating activities 1.1 Receipts from customers 1.2 Payments for (a) exploration & evaluation (b) development (c) production (d) staff costs (e) administration and corporate costs 1.3 Dividends received (see note 3) 1.4 Interest received 1.5 Interest and other costs of finance paid 1.6 Income taxes paid 1.7 Research and development refunds 1.8 Other (provide details if material) 1.9 Net cash from / (used in) operating activities	- (4,109) - - (1,352) (359) - 124 - - - -	- (7,020) - - (2,219) (742) - 151 - - - -
	(5,696)	(9,830)
2. Cash flows from investing activities 2.1 Payments to acquire: (a) property, plant and equipment (b) tenements(see item 10- Gambia Farm-in) (c) investments (d) exploration and evaluation	(30) (2,144) - (12,001)	(46) (2,144) - (17,277)

• See chapter 19 for defined terms

1 September 2016

Page 1

Appendix 5B Mining exploration entity and oil and gas exploration entity quarterly report

Consolidated statement of cash flows	Current quarter $A’000	Year to date (6 months) $A’000
2.2 Proceeds from the disposal of: (a) property, plant and equipment (b) tenements (see item 10) (c) investments (d) other non-current assets 2.3 Cash flows from loans to other entities 2.4 Dividends received (see note 3) 2.5 Other – payment for performance bond 2.6 Net cash from / (used in) investing activities	- - - - - - -	- - - - - - -
	(14,175)	(19,467)
3. Cash flows from financing activities 3.1 Proceeds from issues of shares 3.2 Proceeds from issue of convertible notes 3.3 Proceeds from exercise of share options 3.4 Transaction costs related to issues of shares, convertible notes or options 3.5 Proceeds from borrowings 3.6 Repayment of borrowings 3.7 Transaction costs related to loans and borrowings 3.8 Dividends paid 3.9 Other (provide details if material) 3.10 Net cash from / (used in) financing activities	80,000 - - (3,412) - - - - -	80,000 - - (3,412) - - - - -
	76,588	76,588
4. Net increase / (decrease) in cash and cash equivalents for the period 4.1 Cash and cash equivalents at beginning of period 4.2 Net cash from / (used in) operating activities (item 1.9 above) 4.3 Net cash from / (used in) investing activities (item 2.6 above) 4.4 Net cash from / (used in) financing activities (item 3.10 above) 4.5 Effect of movement in exchange rates on cash held 4.6 Cash and cash equivalents at end of period	35,299 (5,696) (14,175) 76,588 (750)	46,978 (9,830) (19,467) 76,588 (3,003)
	91,266	91,266

• See chapter 19 for defined terms 1 September 2016

Page 2

Appendix 5B Mining exploration entity and oil and gas exploration entity quarterly report

5. Reconciliation of cash and cash equivalents at the end of the quarter (as shown in the consolidated statement of cash flows) to the related items in the accounts	Current quarter $A’000	Previous quarter $A’000
5.1 Bank balances 5.2 Call deposits 5.3 Bank overdrafts 5.4 Other – Term deposits 5.5 Cash and cash equivalents at end of quarter (should equal item 4.6 above)	12,428 51,638 - 27,200	31,381 18 - 3,900
	91,266	35,299

6.	Payments to directors of the entity and their associates	Current quarter
		$A'000
6.1	Aggregate amount of payments to these parties included in item 1.2	408
6.2	Aggregate amount of cash flow from loans to these parties included
	in item 2.3
6.3	Include below any explanation necessary to understand the transactions included in
	items 6.1 and 6.2

7. Payments to related entities of the entity and their associates

Current quarter $A'000

• 7.1 Aggregate amount of payments to these parties included in item 1.2 7.2 Aggregate amount of cash flow from loans to these parties included in item 2.3

• 7.3 Include below any explanation necessary to understand the transactions included in items 7.1 and 7.2

• See chapter 19 for defined terms 1 September 2016

Page 3

Appendix 5B Mining exploration entity and oil and gas exploration entity quarterly report

	8. Financing facilities available Add notes as necessary for an understanding of the position Total facility amount at quarter end $A’000 Amount drawn at quarter end $A’000 8.1 Loan facilities - - 8.2 Credit standby arrangements - - 8.3 Other (please specify) - - 8.4 Include below a description of each facility above, including the lender, interest rate and whether it is secured or unsecured. If any additional facilities have been entered into or are proposed to be entered into after quarter end, include details of those facilities as well.	Total facility amount at quarter end $A’000	Amount drawn at quarter end $A’000
		-	-
		-	-
		-	-

9. Estimated cash outflows for next quarter	$A’000
9.1 Exploration and evaluation 9.2 Development 9.3 Production 9.4 Staff costs 9.5 Administration and corporate costs 9.6 Other (provide details if material) 9.7 Total estimated cash outflows	27,000 - - 750 350 -
	28,100

10. Changes in tenements (items 2.1(b) and 2.2(b) above)	Tenement reference and location	Nature of interest	Interest at beginning of quarter	Interest at end of quarter
10.1 Interests in mining tenements and petroleum tenements lapsed, relinquished or reduced
10.2 Interests in mining tenements and petroleum tenements acquired or increased	The Gambia Block A2 and Block A5	Petroleum (Exploration, Development and Production) Licence	nil	80%

• See chapter 19 for defined terms 1 September 2016

Page 4

Appendix 5B

Mining exploration entity and oil and gas exploration entity quarterly report

Compliance statement

• 1 This statement has been prepared in accordance with accounting standards and policies which comply with Listing Rule 19.11A.

• 2 This statement gives a true and fair view of the matters disclosed.

Sign here: ............................................................ Date: 31 July 2017 (Company secretary)

Print name: Peter Thiessen

Notes

1. The quarterly report provides a basis for informing the market how the entity’s activities have been financed for the past quarter and the effect on its cash position. An entity that wishes to disclose additional information is encouraged to do so, in a note or notes included in or attached to this report.

2. If this quarterly report has been prepared in accordance with Australian Accounting Standards, the definitions in, and provisions of, AASB 6: Exploration for and Evaluation of Mineral Resources and AASB 107: Statement of Cash Flows apply to this report. If this quarterly report has been prepared in accordance with other accounting standards agreed by ASX pursuant to Listing Rule 19.11A, the corresponding equivalent standards apply to this report.

3. Dividends received may be classified either as cash flows from operating activities or cash flows from investing activities, depending on the accounting policy of the entity.

4. See chapter 19 for defined terms 1 September 2016

Page 5