FAR LIMITED — Interim / Quarterly Report 2017

Sep 4, 2017

Financial Report for the half-year ended 30 June 2017

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Half-Year Financial Report 2017

Contents

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Page

• 2 Directors’ Report

• 8 Auditor’s Independence Declaration

• 9 Independent Auditor’s Report

• 11 Directors’ Declaration

• 12 Condensed Consolidated Statement of Profit or Loss and Other Comprehensive Income

• 13 Condensed Consolidated Statement of Financial Position

• 14 Condensed Consolidated Statement of Changes in Equity

• 15 Condensed Consolidated Statement of Cash Flows

• 16 Notes to the Financial Statements

1

Half-Year Financial Report 2017 Directors’ Report

The directors of FAR Limited submit herewith the Financial Report of FAR Ltd and its subsidiaries (‘the Consolidated Entity’) for the half-year ended 30 June 2017. In order to comply with the provisions of the Corporations Act 2001, the directors report as follows:

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

Mr N J Limb Ms C M Norman Mr A E Brindal (Retired 29 May 2017) Mr B J M Clube Mr R G Nelson Mr T R Woodall (Appointed 1 Aug 2017)

All directors held office during and since the end of the period unless otherwise stated.

PRINCIPAL ACTIVITIES

The principal activities of the Company are:

• Securing exploration projects;

• Conducting exploration appraisal and evaluation for oil and gas resources; and

• Realising value from oil exploration and production interests.

FINANCIAL PERFORMANCE

	H1 FY17	H1 FY16	Change
	$	$	%
Profit & loss
Revenues	201,695	85,047	137%
Expenses	(22,549,790)	(11,403,700)	107%
Loss for the period	(22,348,095)	(11,318,653)	99%
Basic EPS (cents)	(0.46)	(0.29)	7%
Cash flows
Operating cash flow	(17,170,947)	(10,577,455)	62%
Investing cash flow	(12,125,617)	(44,069,437)	(72%)
Financing cash flow	76,587,542	60,127,254	27%
Financial position	30 Jun 17	31 Dec 2016	0%
Net assets	192,971,047	144,800,225	33%
Cash balance	91,266,078	46,978,179	94%

LOSS FOR THE PERIOD

The loss for the period of $22,348,095 was $11,029,442 higher than the previous corresponding period principally due to higher exploration expenses of $17,159,164 and higher foreign exchange losses of $2,678,983 compared with $8,299,885 and $19,115 respectively for the same period last year. The increase in exploration expenses relate to the Senegal drilling campaign, exploration drilling expenses and pre-development work and The Gambia pre-award costs. The foreign exchange loss is primarily the result of the revaluation of the US Dollar bank account.

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Half-Year Financial Report 2017 Directors’ Report

FINANCIAL POSITION

Net assets increased by 33% to $192,971,047 during the half-year. Total assets increased by $66,304,204 to $218,004,579 and total liabilities increased by $18,133,382 to $25,033,532. The strengthening of the balance sheet was due mainly to the completion of an $80,000,000 capital raising before costs completed in May 2017.

Cash at 30 June 2017 was $91,266,078, an increase of $47,290,978 or 94% from the prior year end, primarily the result of the capital raising and after funding $10,086,097 of Senegal drilling costs capitalised, $14,888,099 of exploration and evaluation costs expensed and Gambia farm-in costs of $2,143,981 during the period.

Exploration and evaluation assets increased by $22,624,818 during the half to $124,331,584 reflecting the capitalisation of Senegal offshore well expenditure of $15,626,596 and the purchase costs of The Gambia farm-in to Blocks A2 and A5 of $7,104,430.

Trade and other payables increased by $17,992,498 during the half to $23,951,207. The current balance predominantly relates to Senegal well costs and the balance of the Gambia farm-in purchase costs.

REVIEW OF OPERATIONS

SENEGAL

The Company and its joint venture partners participated in four successful wells to both appraise the SNE oil field and test one previously undrilled exploration prospect offshore Senegal during the first half of 2017.

The SNE-5, VR-1 and SNE-6 wells were drilled to complete the appraisal of the SNE oil field and the FAN South-1 well was being drilled to test a new, undrilled prospect within tie-back range of a future development at SNE. Each well was drilled safely, efficiently, ahead of schedule and below budget.

These wells confirmed the following SNE field properties:

• ~100m gross oil column.

• High quality 32⁰ API oil.

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

• Connectivity of upper reservoirs between the SNE-5 and SNE-6 wells.

FAN South-1 found oil and gas bearing reservoir units and work is ongoing to integrate the well results and understand the significance of this well to future exploitation plans offshore Senegal.

This third drilling campaign was completed with the drilling of the SNE North-1 well (in the second half of the year), the eleventh successful well to be drilled offshore Senegal by the joint venture to date, with 100% success rate.

SNE-5

The objective of the SNE-5 well was to evaluate and flow oil from two principal units in the upper reservoirs that are within the oil leg at this location.

Oil flow rates recorded from these upper reservoir units were in line with or exceeded expectations. The SNE-5 well results show a good correlation with previous SNE wells and provide further evidence of the large extent of the SNE field, the material contribution of the upper reservoir units to the SNE oil resource volumes and the ability to produce from the upper reservoir units at commercially viable rates.

The results of the SNE-5 well were announced on 8 March 2017. The well results are consistent with the sand distribution models of the SNE upper reservoirs and give further confidence in the ability to optimally locate and design development wells.

Initial results from the well are as follows:

• Two drill stem tests (DST) were conducted within the upper reservoirs, confirming confidence in the deliverability of these units.

• DST 1a: 18m zone in the S480 reservoir, flowed at a maximum rate 4,500 bopd, stabilized rate 2,500 bopd on 40/64” choke, and 3,000 bopd on 56/64” choke – 24 hour each test. This flow rate was better than the flow rate achieved from the same reservoir in the SNE-3 well.

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Half-Year Financial Report 2017 Directors’ Report

• DST 1b: an additional, and previously untested S460 reservoir section of 8.5m was comingled with the 1a DST to deliver a maximum flow rate 4,200 bopd, average stabilised rate 3,900 bopd on 64/64” choke, above expectations for this interval.

• Multiple samples of oil, gas and water were collected from the well which were consistent with samples taken from all other SNE wells.

• Depths to the reservoirs, depth to gas oil contact (GOC) and oil water contact (OWC) were on prognosis.

• Confirmation of reservoir quality and correlation of the principal reservoir units.

• Oil column thickness confirmed at 100m gross, as seen at all other SNE oil field wells to date.

VR-1

Drilling operations on the VR-1 well reached a depth of 2759m, wireline logging and sampling through the SNE section were completed and the well was deepened into the Aptian carbonate objectives below the SNE field.

FAR’s evaluation of the well results were announced on 27 March 2017 and are as follows:

• The SNE reservoir units were in oil as per prognoses.

• The lower, S500 series S520 reservoir (16m in oil), a key reservoir to the phase 1 development of the SNE field, exhibited excellent reservoir properties, superior to all other reservoirs sampled in the SNE field to date.

• The deeper S540 reservoir (11m in oil) has only been seen in the SNE-2 well in oil (2m).

• Oil samples were taken.

• Along with other appraisal wells, the well confirmed a 97m gross oil column with greater than expected net pay and thickest net pay of all appraisal wells drilled to date.

• Hydrocarbon indications, including evidence of oil were encountered after deepening VR-1 to a total depth of 3,899m into a secondary exploration target in the Aptian carbonate section however, this was not of commercial significance.

SNE-6

The SNE-6 well, along with the SNE-5 well, formed part of an interference test designed to demonstrate connectivity within the upper reservoirs in the SNE oil field. Pressure data from SNE-6 immediately confirmed connectivity with SNE5.

A DST was carried out over the S480 upper reservoirs of the field, and connectivity of these reservoirs was again established with the SNE-5 well. The results of this interference test successfully addressed the remaining objective of the SNE field appraisal program.

The DST produced the following results, announced on 18 May 2017:

• 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.

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.

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Half-Year Financial Report 2017 Directors’ Report

FAN South-1

On completion of SNE-6, the FAN South-1 well was drilled into the South Fan prospect. The well was spudded in June 2017 and the results were announced on 11 July 2017.

The FAN South-1 well reached total depth of 5,343m. The well had dual targets of an Upper Cretaceous stacked multilayer channelised turbidite fan prospect and a Lower Cretaceous base of slope turbidite fan prospect, similar to the FAN1 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 2,175m and approximately 90km offshore in the Sangomar Deep Offshore block, 30 km south west of the FAN-1 exploration well.

SNE resource updates

On 7 February 2017, the Company released its assessment of the offshore Senegal undrilled prospect inventory following delivery of final 3D seismic products from the 2,400km² survey over the Rufisque, Sangomar, Sangomar Deep (“RSSD”) blocks and the 400km² survey over the Djiffere block in Q4 of 2016.

The prospective resource assessment was completed by RISC Operations Pty Ltd (“RISC”) and set out in its Independent Resources Report highlights that FAR has, “a material and robust exploration portfolio, which we expect will be tested in coming years”.

The individual prospect resource estimates are detailed in the ASX announcement of 7 February and assess the probabilistic resource evaluation carried out by the Company in accordance with industry standard SPE-PRMS definitions.

Senegal project arbitration

On 20 June 2017, the Company made a request to the International Chamber of Commerce in Paris to commence arbitration proceedings to resolve a Joint Operating Agreement dispute in relation to the Company’s rights of preemption with respect to the reported sale of ConocoPhillips’ 35% interest in the RSSD Joint Venture to Woodside Petroleum Limited. The arbitration proceedings may take in the order of twelve months to reach a determination at which point the Company will be in a position to make any decision in relation to any award relating to its pre-emption rights.

GAMBIA

During the period, the Company acquired an 80% interest in blocks A2 and A5 offshore The Gambia following the completion of a farm-in deal with New York and Johannesburg Stock Exchange listed Erin Energy Corporation (“ERIN”). The acquisition was subject to approval of the Government of the Republic of the Gambia that was announced shortly after the end of the period (refer ASX announcement 3 July 2017).

Blocks A2 and A5 are adjacent to and on trend with the Company’s SNE oil field discovery, cover an area of approximately 2,682km[2] and lie approximately 30km offshore in water depths ranging from 50 to 1,200m.

The Company intends to undertake 3D seismic reprocessing and interpretation during 2017 to mature prospects for drilling in late 2018.

Under the terms of the farm-in agreement, a wholly owned subsidiary of the Company, has acquired an 80% interest and Operatorship of offshore Blocks A2 and A5 from ERIN. Following Government approval the Company made an upfront payment of US$5.18 million and will 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 are less than US$8.0 million then the balance is to be paid in cash. The Company’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 will satisfy the current period work commitments for Blocks A2 and A5. The Company 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 the Company, 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.

The acquisition significantly expands the Company’s exploration portfolio in the offshore Mauritania-Senegal-GuineaBissau Basin in West Africa.

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Half-Year Financial Report 2017 Directors’ Report

GUINEA-BISSAU

During the reporting period, negotiations concluded with the National oil company of Guinea-Bissau, Petroguin, to revise the terms of both the Sinapa and Esperanca Licences in which the Company has interests (refer ASX release 4 April 2017).

Under the revised Licence terms, the Company will now have a 21.42% participating and paying interest in the permits, an increase from the 15% participating and 21.42% paying interests as previously reported. These changes reflect the fact that Petroguin will no longer have a participating interest in the joint venture prior to a commercial discovery. Upon making a commercial discovery, Petroguin will have a reduced participating and paying interest of 10% and FAR and Svenska will respectively have interests of 19.28% and 70.72%.

In addition, the new Licence terms negotiated include more favourable arrangements for deep water investment including a reduction to production royalty rates payable to Government.

These changes to Licence terms are consistent with the joint venture’s new strategy to focus on the shelf edge areas of the Sinapa and Esperanca Licences which display a similar geological setting to offshore Senegal and the Company’s SNE field discovery.

In recognition of this new strategy and to provide adequate time to further evaluate the newly acquired 3D seismic data offshore Guinea-Bissau, the joint venture has been awarded a three-year extension to the current Licence periods, now ending on 25 November 2020.

During these Licence periods, the work obligation is to drill one exploration well on each Licence with a minimum expenditure commitment for each Licence of US$3 million (gross).

Government approval for these contract amendments was received following the end of the period (refer ASX release 25 August 2017).

KENYA

On 14 July 2017, the Company formally notified the Ministry of Energy & Petroleum in Kenya of a force majeure event over Block L6. FAR will continue to work with the Ministry of Energy & Petroleum to resolve the underlying issues, namely the inability to access the land due to security issues.

The Company 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) remains in default for non-payment of cash calls in 2015 and 2016 and remains in default. Discussions continue with Pancontinental to resolve the default as soon as possible.

AUSTRALIA

The Company has applied to surrender the WA-457-P permit at the end of the first 3-year exploration period after satisfying all the work commitments. Confirmation of the surrender is yet to be received from the National Offshore Petroleum Titles Office (NOPTA).

In WA-458-P, completion of the 3D seismic survey acquired over the block is scheduled for late 2017 subject to environmental approvals, availability of a seismic vessel and the granting of an extension to the current period by NOPTA. The application for an extension was submitted to NOPTA in early June 2017. The permit remains in the first 3- year exploration term.

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Half-Year Financial Report 2017 Directors’ Report

AUDITOR’S INDEPENDENCE DECLARATION

The directors’ report includes the auditor’s independence declaration which is included on page 8 of the half-year financial report.

Signed in accordance with a resolution of the directors made pursuant to Section 306(3) of the Corporations Act 2001.

On behalf of the Directors

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Mr N J Limb Chairman Melbourne, 5 September 2017

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Deloitte Touche Tohmatsu ABN 74 490 121 060

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

DX 111

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

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

5 September 2017

Dear Board Members

FAR Limited

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

As lead audit partner for the review of the financial statements of FAR Limited for the half-year ended 30 June 2017, I declare that to the best of my knowledge and belief, there have been no contraventions of:

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

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

Yours sincerely

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DELOITTE TOUCHE TOHMATSU

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Ryan Hansen Partner Chartered Accountant

Liability limited by a scheme approved under Professional Standards Legislation Member of Deloitte Touche Tohmatsu Limited

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

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DX 111 Tel: +61 (0) 3 9671 7000 Fax: +61 (0) 3 9671 7001 www.deloitte.com.au

Independent Auditor’s Review Report to the members of FAR Limited

Report on the Half-Year Financial Report

We have reviewed the accompanying half-year financial report of FAR Limited, which comprises the condensed consolidated statement of financial position as at 30 June 2017, the condensed consolidated statement of profit or loss and other comprehensive income, the condensed consolidated statement of changes in equity and the condensed consolidated statement of cash flows for the half-year ended, and a summary of significant accounting policies and other explanatory information, and the directors’ declaration of the consolidated entity comprising the company and the entities it controlled at the end of the half-year or from time to time during the half-year as set out in pages 11 to 21.

Directors’ Responsibility for the Half-Year Financial Report

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

Auditor’s Responsibility

Our responsibility is to express a conclusion on the half-year financial report based on our review. We conducted our review in accordance with Auditing Standard on Review Engagements ASRE 2410 Review of a Financial Report Performed by the Independent Auditor of the Entity , in order to state whether, on the basis of the procedures described, we have become aware of any matter that makes us believe that the half-year financial report is not in accordance with the Corporations Act 2001 including: giving a true and fair view of FAR Limited’s financial position as at 30 June 2017 and its performance for the half-year ended on that date; and complying with Accounting Standard AASB 134 Interim Financial Reporting and the Corporations Regulations 2001 . As the auditor of FAR Limited, ASRE 2410 requires that we comply with the ethical requirements relevant to the audit of the annual financial report.

A review of a half-year financial report consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with Australian Auditing Standards and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Auditor’s Independence Declaration

In conducting our review, we have complied with the independence requirements of the Corporations Act 2001 . We confirm that the independence declaration required by the Corporations Act 2001 , which has been given to the directors of FAR Limited, would be in the same terms if given to the directors as at the time of this auditor’s review report.

Liability limited by a scheme approved under Professional Standards Legislation. Member of Deloitte Touche Tohmatsu Limited

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Conclusion

Based on our review, which is not an audit, we have not become aware of any matter that makes us believe that the half-year financial report of FAR Limited is not in accordance with the Corporations Act 2001 , including:

• (a) giving a true and fair view of the consolidated entity’s financial position as at 30 June 2017 and of its performance for the half-year ended on that date; and

• (b) complying with Accounting Standard AASB 134 Interim Financial Reporting and the Corporations Regulations 2001 .

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DELOITTE TOUCHE TOHMATSU

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Ryan Hansen Partner Chartered Accountants Melbourne, 5 September 2017

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Half-Year Financial Report 2017 Directors’ Declaration

The directors declare that:

• (a) in the directors’ opinion, there are reasonable grounds to believe that the Company will be able to pay its debts as and when they become due and payable; and

• (b) in the directors’ opinion, the attached financial statements and notes thereto are in accordance with the Corporations Act 2001, including compliance with accounting standards, the Corporations Regulations 2001 and other mandatory professional reporting requirements; and giving a true and fair view of the financial position as at 30 June 2017 and of the performance of the Consolidated Entity for the half-year ended on that date.

Signed in accordance with a resolution of the directors made pursuant to s.303(5) of the Corporations Act 2001.

On behalf of the Directors

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Mr N J Limb Chairman Melbourne, 5 September 2017

11

Condensed Consolidated Statement of Profit or Loss and Other Comprehensive Loss For the Half-Year Ended 30 June 2017

Note Continuing operations Interest income Depreciation and amortisation expense Exploration expense 3 Corporate administration expenses Employee benefits expense 3 Consulting expense Foreign exchange loss Other expenses Loss before tax Income tax expense Loss for the period Other comprehensive loss Exchange differences arising on translation of foreign operations Total comprehensive loss for the period Loss per share: Basic loss (cents per share) Diluted loss (cents per share)	Half-year ended
	30 Jun 2017 AU$ 30 Jun 2016 AU$
	201,695 85,047
	(18,460) (18,688)
	(17,159,164) (8,299,885)
	(424,642) (349,725)
	(1,900,355) (2,184,300)
	(183,270) (296,839)
	(2,678,983) (19,115)
	(184,916) (235,148)
	(22,348,095) (11,318,653)
	- -
	(22,348,095) (11,318,653)
	(6,235,079) (1,329,524)
	(28,583,174) (12,648,177)
	(0.46) (0.29)
	(0.46) (0.29)

Notes to the financial statements are included on pages 16 to 21.

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Condensed Consolidated Statement of Financial Position As at 30 June 2017

Note CURRENT ASSETS Cash and cash equivalents 4 Trade and other receivables 5 Other financial assets Total Current Assets NON CURRENT ASSETS Property, plant and equipment Exploration and evaluation assets 6 Total Non-Current Assets TOTAL ASSETS CURRENT LIABILITIES Trade and other payables 7 Provisions Total Current Liabilities NON-CURRENT LIABILITIES Provisions Total Non-Current Liabilities TOTAL LIABILITIES NET ASSETS EQUITY Issued Capital 8 Reserves Accumulated losses TOTAL EQUITY	30 Jun 2017 31 Dec 2016 AU$ AU$
	91,266,078 46,978,179
	1,960,965 2,575,664
	122,017 120,299
	93,349,060 49,674,142
	323,935 319,467
	124,331,584 101,706,766
	124,655,519 102,026,233
	218,004,579 151,700,375
	23,951,207 5,958,709
	1,007,930 885,571
	24,959,137 6,844,280
	74,395 55,870
	74,395 55,870
	25,033,532 6,900,150
	192,971,047 144,800,225
	374,521,076 297,933,534
	6,458,781 12,527,406
	(188,008,810) (165,660,715)
	192,971,047 144,800,225

Notes to the financial statements are included on pages 16 to 21.

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Condensed Consolidated Statement of Changes in Equity For the Half-Year Ended 30 June 2017

Balance at 1 January 2016 Loss for the period Exchange differences arising on translation of foreign operations Total comprehensive income for the period Issue of shares Issue of ordinary shares under share option plan Share issue costs Issue of performance rights Balance at 30 June 2016 Balance at 1 January 2017 Loss for the period Exchange differences arising on translation of foreign operations Total comprehensive income for the period Issue of shares Share issue costs Issue of performance rights Cancellation of performance rights Balance at 30 June 2017	Share Capital AU$ 237,806,280 - -	Reserves Share based payments reserve (i) Foreign currency translation reserve(ii) Total AU$ AU$ AU$ 5,955,222 2,427,509 8,382,731 - - - - (1,329,524) (1,329,524)	Accumulated losses Total attributed to equity holders of parent AU$ AU$ (143,900,741) 102,288,270 (11,318,653) (11,318,653) - (1,329,524)
	-	- (1,329,524) (1,329,524)	(11,318,653) (12,648,177)
	60,000,000 2,728,000 (2,600,746) -	- - - - - - - - - 1,159,664 - 1,159,664	- 60,000,000 - 2,728,000 - (2,600,746) 1,159,664
	297,933,534	7,114,886 1,097,985 8,212,871	(155,219,394) 150,927,011
	297,933,534 - -	8,445,445 4,081,961 12,527,406 - - - - (6,235,079) (6,235,079)	(165,660,715) 144,800,225 (22,348,095) (22,348,095) - (6,235,079)
	-	- (6,235,079) (6,235,079)	(22,348,095) (28,583,174)
	80,000,000 (3,412,458) -	- - - - - - 327,495 - 327,495 (161,041) (161,041)	- 80,000,000 - (3,412,458) - 327,495 (161,041)
	374,521,076	8,611,899 (2,153,118) 6,458,781	(188,008,810) 192,971,047

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

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

Notes to the financial statements are included on pages 16 to 21.

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Condensed Consolidated Statement of Cash Flows for the Half-Year Ended 30 June 2017

Note CASH FLOWS FROM OPERATING ACTIVITIES Payments to employees and corporate suppliers Payments for exploration and evaluation expensed Net cash used in operating activities CASH FLOWS FROM INVESTING ACTIVITIES Interest received Payments for exploration and evaluation capitalised Payments for property, plant and equipment Payment of farm-in costs Advanced to Joint Venture Net cash (used in)/provided by investing activities CASH FLOWS FROM FINANCING ACTIVITIES Proceeds from issue of shares Payment for share issue costs Net cash provided by financing activities NET INCREASE/(DECREASE) IN CASH AND CASH EQUIVALENTS Cash and cash equivalents at the beginning of the period Effects of exchange rate changes on cash and cash equivalents Cash and cash equivalents at the end of the financial period 4	Half-year ended
	30 Jun 2017 AU$ 30 Jun 2016 AU$
	(2,332,848) (1,965,407)
	(14,838,099) (8,612,048)
	(17,170,945) (10,577,455)
	150,553 84,558
	(10,086,097) (44,098,806)
	(46,092) (40,467)
	(2,143,981) -
	- (14,722)
	(12,125,617) (44,069,437)
	80,000,000 62,728,000
	(3,412,458) (2,600,746)
	76,587,542 60,127,254
	47,290,978 5,480,362
	46,978,179 60,670,897
	(3,003,079) 127,645
	91,266,078 66,278,904

Notes to the financial statements are included on pages 16 to 21.

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Notes to the Financial Statements For the Half-Year Ended 30 June 2017

1. SIGNIFICANT ACCOUNTING POLICIES

a. Statement of compliance

The half-year financial report is a general purpose financial report prepared in accordance with the Corporations Act 2001 and Accounting Standard AASB 134 Interim Financial Reporting . Compliance with AASB 134 ensures compliance with International Financial Reporting Standard IAS 34 Interim Financial Reporting. The half-year financial report does not include notes of the type normally included in an annual financial report and shall be read in conjunction with the most recent annual financial report.

b. Basis of preparation

The condensed consolidated financial statements have been prepared on the basis of historical cost except, where applicable, for the revaluation of certain non-current assets and financial instruments. All amounts are presented in Australian dollars, unless otherwise noted.

The accounting policies and methods of computation adopted in the preparation of the half-year financial report are consistent with those adopted and disclosed in the company’s annual financial report for the year ended 31 December 2016.

c. Going concern

The Directors believe that it is appropriate to prepare the condensed consolidated financial statements on a going concern basis. As at 30 June 2017, the Group’s current assets exceeded current liabilities by $68,389,923 and the Group has cash and cash equivalents of $91,266,078. 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. For further details of future commitments refer to Note 9. 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, because the Company believes it has adequate financing 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 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 and appraisal/evaluation 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.

16

Notes to the Financial Statements For the Half-Year Ended 30 June 2017

2. 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 undertakes exploration of oil and gas in Australia and Africa. The identification of the Group’s reporting segments remains consistent with prior periods, with management allocating resources to segments on a geographical basis with the inclusion of a ‘corporate’ segment which captures all head office and administrative income, expenses, assets and liabilities.

Information regarding these segments is presented below. The accounting policies of the reportable segments are the same as those of the Group.

Segment Assets and Liabilities

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

Australia Guinea-Bissau Kenya Senegal Gambia(i) Other Corporate Total assets and liabilities	Assets Liabilities
	30 Jun 2017 31 Dec 2016 30 Jun 2017 31 Dec 2016
	AU$ AU$ AU$ AU$
	- - 20,000 -
	1,129,750 1,278,206 20,231 18,765
	1,042,793 1,176,802 24,656 16,389
	121,105,282 102,561,602 17,985,248 5,392,889
	7,104,430 - 5,342,211 -
	8,971 9,536 10,698 4,773
	87,613,354 46,674,229 1,630,488 1,467,334
	218,004,579 151,700,375 25,033,532 6,900,150

(i) At the end of the period the Government of The Gambia approved the assignment of an 80% interest in offshore Blocks A2 and A5 in the Gambia to a wholly owned subsidiary of FAR from Erin Energy Corporation. Under the terms of the farm-in agreement FAR is required to make an upfront payment of $6,734,269 (US$5.18 million) representing the Purchase Cost plus adjustments. $2,143,981 of this amount was paid during the period and the balance of $4,972,050 was paid subsequent to period end.

Segment Revenue and Results

The following is an analysis of the Group’s revenue and results by reportable segment for the period under review:

Australia Guinea-Bissau Kenya Senegal Other Corporate Total for continuing operations Income tax expense Loss after tax (continuing operations)	Interest Income Segment Loss
	30 Jun 2017 30 Jun 2016 30 Jun 2017 30 Jun 2016
	AU$ AU$ AU$ AU$
	- - (39,550) (926,696)
	- - (358,970) (358,048)
	- - (90,813) (243,189)
	- - (15,207,241) (6,694,501)
	- 152 (1,462,590) (79,718)
	201,695 84,895 (5,188,931) (3,016,501)
	201,695 85,047 (22,348,095) (11,318,653)
	- - - -
	- - (22,348,095) (11,318,653)

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

17

Notes to the Financial Statements For the Half-Year Ended 30 June 2017

3. LOSS FOR THE PERIOD

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

Exploration expense Australia Guinea-Bissau Senegal Kenya New ventures and other Employee benefit expense: - Short-term employee benefits – salaries and fees - Recharge of salaries and fees to exploration expense - Short-term employee benefits – termination Post-employment benefits - Defined contribution plans - Share based payments – equity settled - Increase in employee benefits provisions	Half-year ended 30 Jun 2017 AU$ 30 Jun 2016 AU$ (39,550) (926,696) (358,970) (358,048) (15,207,241) (6,694,501) (90,813) (243,189) (1,462,590) (77,451) (17,159,164) (8,299,885) (1,625,819) (1,436,249) 624,684 556,692 (470,138) - (121,743) (97,972) (166,455) (1,159,664) (140,884) (47,107) (1,900,355) (2,184,300)

4. CASH

. CASH
Cash and cash equivalents Cash and cash equivalents held in joint operations	30 Jun 2017 AU$ 31 Dec 2016 AU$ 86,705,255 45,911,456 4,560,823 1,066,723
	91,266,078 46,978,179

5. TRADE AND OTHER RECEIVABLES

Interest receivable Other receivables Prepayments Joint operations receivables	30 Jun 2017 AU$ 31 Dec 2016 AU$ 60,949 9,806 1,181,001 749,255 113,821 177,377 605,194 1,639,226
	1,960,965 2,575,664

18

Notes to the Financial Statements For the Half-Year Ended 30 June 2017

6. EXPLORATION AND EVALUATION

. EXPLORATION AND EVALUATION
Exploration and evaluation expenditure: Opening balance Additions(i) Net foreign currency exchange differences Closing balance	30 Jun 2017 AU$ 31 Dec 2016 AU$ 101,706,766 58,861,246 28,654,236 42,284,176 (6,029,418) 561,344
	124,331,584 101,706,766

• (i) The company’s participating share of the Senegal well costs capitalised for the half year was $15,626,596, inclusive of foreign exchange differences. Also included in additions is the acquisition of an 80% interest in The Gambia Blocks A2 and A5 for the Purchase Cost plus adjustments of $7,104,430.

7. TRADE AND OTHER PAYABLES

Current Trade payables Other payables(i) Joint operation payables(ii)	30 Jun 2017 AU$ 31 Dec 2016 AU$ 1,452,955 405,936 5,378,546 287,615 17,119,706 5,265,158
	23,951,207 5,958,709

(i) Other payables for the current period includes accrued Gambia Block A2 and Block A5 farm-in Purchase Costs of AU $5,103,901 (US $3,850,893).

• (ii) Includes Senegal joint operation payables of $17,053,273 (2016: $5,205,756)

8. ISSUED CAPITAL

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

• (a) The following shares were issued during the current half-year:

• (i) 669,229,868 ordinary fully paid shares were issued at 8 cents per share via a placement to institutional and sophisticated investors on 12 April 2017 (first tranche).

• (ii) 330,770,132 ordinary fully paid shares were issued at 8 cents per share via a placement to institutional and sophisticated investors on 19 May 2017 (second tranche issued upon receiving shareholder approval at the EGM held on 15 May 2017).

19

Notes to the Financial Statements For the Half-Year Ended 30 June 2017

9. COMMITMENTS

In order to maintain rights to tenure of exploration permits, the Group is required to perform minimum work programs specified by various state and national governments. These obligations are subject to renegotiation in certain circumstances such as when application for an extension permit is made and 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 be either 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 expenditure for approved commitments and minimum work program commitments are as follows:

Exploration and evaluation Not longer than 1 year Longer than 1 year and not longer than 5 years Longer than 5 years 0. CONTINGENT LIABILITIES Contingent liabilities Guinea-Bissau – contingent payment from future production Guinea-Bissau – contingent withholding tax liability Kenya L6 – performance Bond	30 Jun 2017 AU$ 31 Dec 2016 AU$ 7,884,225 45,710,644 44,573,323 - - -
	52,457,548 45,710,644
	30 Jun 2017 AU$ 31 Dec 2016 AU$ 16,900,676 17,965,727 738,184 784,704 120,474 118,659
	17,759,334 18,869,090

10. CONTINGENT LIABILITIES

11. PARENT ENTITY

During the period the Parent Entity provided a parent company guarantee to the Ministry of Gambia to guarantee 100% of the work obligations of the Initial Exploration Period of the Blocks A2 and A5 licence Agreement including the drilling of an Exploration Well before 31 December 2018 or such later date if the current licence periods are extended. The maximum amount of the parent company guarantee is US$33,000,000. This parent company guarantee is in addition to those guarantees disclosed in the 2016 Annual Report.

20

Notes to the Financial Statements For the Half-Year Ended 30 June 2017

12. SUBSEQUENT EVENTS

Subsequent Events after balance sheet date

On 11 July 2017 the Company announced that the FAN South-1 exploration well offshore Senegal reached total depth and wire line logging was completed. Oil was discovered and oil samples were obtained from lower Cretaceous reservoirs. Further work is being undertaken to integrate this discovery with the results of the FAN-1 well.

On 7 August 2017 the company announced that the Senegal SNE North-1 exploration well drilled into the Sirius Prospect, to the north of the SNE oil field discovered hydrocarbons at three separate intervals. Additional work is being undertaken to establish the potential commerciality of this discovery and to integrate the results with the block wide data gathered to date.

The Directors are not aware of any other matters or circumstances at the date of this report, other than those referred to in this report, that have significantly affected or may significantly affect the operations, the results of the operations or the state of affairs of the Consolidated Entity in subsequent financial years.

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