FAR LIMITED — Interim / Quarterly Report 2016

Oct 30, 2016

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01 July – 30 September 2016
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Highlights

• The successful completion of the 2015/2016 SNE oil field appraisal drilling and evaluation program (SNE-2, SNE-3, BEL-1 and SNE-4) has progressed the SNE project to the pre-FEED stage (Front End Engineering and Design) with joint venture studies focussed on an SNE anchor development project with scope for expansion and tie-backs.

• FAR’s SNE 2C contingent resource was upgraded 14% to 641 mmbbls (100% basis, recoverable oil, unrisked). The upgrade was independently certified by RISC Operations Pty Ltd and included the results from the new BEL-1 and SNE-4 appraisal wells.

• FAR has assessed SNE to be a commercially viable project after achieving the Minimum Economic Field Size threshold. The Company’s development concept represents a phased FPSO project with a production plateau of 140,000 bbbls/d and first oil expected from 2022.

• ConocoPhillips announced a proposed sale of its Senegal interests to Woodside Petroleum Ltd, subject to Senegal Government approval and co-venturer pre-emption rights.

• Cash and term deposits at the end of the September quarter totalled $50.5 million.

• Forward Senegal program

• Update on FAR’s prospective exploration resources

• Decision to progress FAR’s Djiffere option

Firm two well drilling program to resume offshore from early 2017

Projects update

Offshore Senegal

During the period, FAR Ltd (ASX:FAR) and its joint venture partners undertook extensive evaluation of the data obtained from the highly successful appraisal wells (SNE-2, SNE-3, BEL-1 and SNE-4) completed over 2015/2016 in the SNE oil field offshore Senegal, West Africa.

The five wells drilled to date into the SNE oil field cover a distance of approximately 9 km in a northsouth direction (BEL-1 to SNE-3) and 5km to the east (SNE-4). Most importantly, all of the SNE wells have confirmed a ~100m gross oil column, high quality 32⁰ API oil, and the presence and correlation of principal reservoir units across the field. In addition, flow tests from SNE-2 and SNE-3 have also indicated the potential for commercially viable well production rates.

Highly encouraging results from this drilling and evaluation activity has supported moving the SNE project into the pre-FEED stage (Front End Engineering & Design) with development planning now underway. Studies are currently focussed on optimising and scaling the project development which is expected to form an anchor project with scope for expansion and tie backs. The SNE development project is also well placed to benefit from project optimisation, standardisation, and cost deflation due to the effect of the relatively low oil price environment.

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Figure 2. SNE field outline with well locations and intereted gas-oil and oil-
water contacts
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Figure 1. SNE field location and 3D seismic coverage offshore Senegal.

SNE resource update

RISC Operations Pty Ltd (“RISC”) provided an updated Independent Resources Report for the SNE oil field following the drilling of the successful BEL-1 and SNE-4 appraisal wells. BEL-1 confirmed good quality oil reservoirs in the northern portion of the SNE field. SNE-4 found oil bearing upper reservoir sands of similar quality to those encountered as gas bearing elsewhere in the SNE field.

RISC reviewed and modified a probabilistic resource evaluation carried out by FAR in accordance with industry standard SPE-PRMS definitions and this resulted in a 14% increase to the estimates previously reported by FAR in April 2016, with the SNE field 2C contingent resource increasing to 641 mmbbls (100% basis, recoverable oil, unrisked). This represents the third consecutive contingent resource upgrade for the SNE oil field and highlights that new information from each successful SNE appraisal well has improved the overall level of confidence of the size of the field.

Table 1. Summary of oil contingent resources (MMstb) included in RISC’s August 2016 report*

	Gross	Gross	Gross	Net Attributable	Net Attributable	Net Attributable
	1C	2C	3C	1C	2C	3C
SNE Discovery (MMstb)	348	641	1128	52	96	169
Percentage change from April 2016	+26%	+14%	+5%	+26%	+14%	+5%

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 oil field commercial viability confirmed

FAR determined the Minimum Economic Field Size for a commercial development at SNE has been achieved. This has been achieved in only 21 months from the initial SNE-1 discovery well and highlights the high quality of the SNE oil field. Cairn Energy PLC, the Operator, previously assessed the Minimum Economic Field Size for the SNE project to be approximately 200 million barrels.

FAR completed pre-engineering studies with engineering consultancy AMOG and prepared an SNE field concept development plan based on its P50 (2C) Contingent Resource estimate of 641 mmbbls.

A standalone FPSO development is envisaged as an anchor project with topside expansion capability for later SNE field development phases and satellite tie-backs. FAR’s development concept represents a phased development approach with a plateau production rate of 140,000 bopd and first oil in 2022.

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

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FAR’s cost estimates are as follows:

• Development expenditure: US$13-15/bbl

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

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

Over the last 24 months offshore drilling and subsea costs have decreased by in excess of 20%. Opportunities to further reduce well and subsea costs through design optimisation and standardisation are being investigated. The current market also offers potential, cost-effective FPSO conversion opportunities that could also enable accelerated production.

In its August 2016 Half Yearly Result, Cairn Energy PLC reported economic scenarios for a standalone SNE development project (see graphs below). Breakeven oil price was estimated at US$35/bbl and based on a US$70/barrel oil price; NPV at FID was US$12.5 per barrel and an ungeared IRR at FID of 38%. Cairn’s valuations are consistent with FAR’s estimates.

Standalone SNE Development: 2C Contingent Recoverable Resource

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Source: Cairn Energy Half Yearly Result 16/08/2016

Proposed conditional sale of ConocoPhillips interest in Senegal

FAR notes public announcements made by ConocoPhillips (COP) and Woodside Petroleum Ltd (WPL) in relation to the proposed sale of COP’s Senegal assets.

As noted by both COP and WPL in announcements of 14 July, completion of the transaction is subject to the rights of partners to pre-empt and Senegal Government approval.

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

FAR is not aware that the Government has advised COP of its approval of the transaction.

FAR will update the market of any material developments.

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

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Senegal 3D seismic

The 2015 3D seismic survey covering 2,400km[2] over the Senegal joint venture Sangomar and Rufisque blocks was completed at the end of 2015. Seismic data processing took place over the June 2016 half. Preliminary products have now been received and final products began to be received over the September quarter.

This seismic data provides important new 3D coverage over a highly prospective geological shelf trend that contains several leads and prospects along an area that extends from SNE in a north east direction towards the Rufisque Dome. The map in Figure 3 shows the Senegal JV 3D seismic survey (in blue).

The Djiffere 3D seismic survey covering 400km[2] over the north western portion of the Djiffere block has also been acquired exclusively by FAR as an extension to the larger RSSD seismic survey.

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Figure 3: Senegal blocks showing 3D seismic coverage

The survey was completed at the end of 2015 and preliminary processed products have been arriving over the September quarter with final products expected to arrive at the end of 2016. FAR’s deadline to exercise its farm-in option will be the later of 31 October 2016 and execution of the Government Arête approving the completion of the current period work program commitments. The 3D seismic program acquired by FAR allows Trace Atlantic to meet these work program commitments and is pending Government approval which will not be unreasonably withheld. The map in Figure 3 shows the FAR Djiffere 3D seismic survey (in red).

The western part of Djiffere block is located along the same geological shelf trend as SNE, with one lead estimated by FAR to contain in excess of 100 mmbbls of unrisked prospective resources. FAR has an option agreement with Trace Atlantic to earn a 75% interest in Djiffere by drilling an exploration well before 31 July 2018 (subject to Government approvals).

New Senegal drilling program

FAR expects further appraisal drilling on the SNE oil field to start in early 2017. This drilling activity is planned to evaluate the connectivity of the upper reservoirs and improve definition and scale of the first phase development project.

The new Senegal drilling program is based on two firm wells plus options and FAR is fully funded through the firm well program. The drilling program objectives are:

• Improving SNE project definition in terms of scale

• Confirm volumes, connectivity and productivity

• Interference program between wells

• Evaluate reservoirs not tested to date

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

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

Offshore Guinea-Bissau

New 3D seismic data acquired over the shelf edge has been shot 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 has been processed and interpreted and joint venture technical meetings are now taking place.

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

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

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Figure 4: Location of FAR blocks offshore Guinea-Bissau

Kenya L6

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.

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

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

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

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

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Australia

FAR has received final processed 3D seismic data over the majority of the WA-458-P block and is planning to acquire new 3D seismic over the remainder. The seismic contractor, CGG, has now secured environmental approvals for the new data acquisition over the Glomar Shoals. As previously advised, FAR commenced the relinquishment of the WA- 457P block and intends to leave in good standing.

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

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Figure 5: Location of WA-457-P and WA-458-P

Management comment

FAR Ltd Managing Director, Cath Norman said, “The SNE project continued to advance over the September quarter and is now at the Pre-FEED stage with joint venture development planning underway. The joint venture focus is on optimising and scaling a first phase development project”.

“FAR delivered a third upgrade to the SNE oil field contingent resources of +14% to a 2C of 641 mmbbls (100% basis, recoverable oil, unrisked) and prepared a detailed concept development plan that supports FAR’s view that SNE is a world class oil field that can become a commercial development”.

“FAR has assessed the SNE field and has surpassed the Minimum Economic Field Size (“MEFS”) threshold. FAR’s 1C of 348 mmbbls (100% basis, recoverable oil, unrisked) compares favourably to Cairn Energy’s previous assessment that MEFS for the SNE project is approximately 200 mmbbls”.

“With respect to the recent announcement by ConocoPhillips that the proposed transaction with Woodside has been completed, FAR has stated its position in an announcement to the ASX earlier this morning. FAR will update our shareholders and the market as material information comes to light.”

“FAR finished the September quarter with $50.5M in cash and no debt and is well placed to participate in the upcoming two firm well drilling program.

“FAR is looking forward to resuming offshore Senegal drilling activity in early 2017, with a focus on improving our understanding of the connectivity of the upper reservoir units in order to optimise the SNE development.”

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

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Disclaimers

*Prospective Resource Estimates Cautionary Statement - With respect to the prospective resource estimates contained within this report, it should be noted that the estimated quantities of Petroleum that may potentially be recovered by the future application of a development project may relate to undiscovered accumulations. These estimates have an associated risk of discovery and risk of development. Further exploration and appraisal is required to determine the existence of a significant quantity of potentially moveable hydrocarbons.

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

Competent Person Statement Information - 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 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.

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

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Project table

Project and Location	Tenement	Beneficial Interest	Acquired during	Disposed during
		at end of quarter	the 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.

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

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Top 10 shareholders (as at 24 October 2016)

	Shareholder	Units	%
1.	FARJOY PTY LTD	451,963,236	10.13
2.	J P MORGAN NOMINEES AUSTRALIA LIMITED	381,720,392	8.56
3.	HSBC CUSTODY NOMINEES (AUSTRALIA) LIMITED	310,908,695	6.97
4.	BNP PARIBAS NOMS PTY LTD	224,706,811	5.04
5.	CITICORP NOMINEES PTY LIMITED	154,830,823	3.47
6.	NATIONAL NOMINEES LIMITED	114,679,548	2.57
7.	MR OLIVER LENNOX-KING	75,647,869	1.70
8.	TOAD FACILITIES PTY LTD	67,528,589	1.51
9.	FOUNTAIN OAKS PTY LTD	34,200,366	0.77
10.	FLOTECK CONSULTANTS LIMITED	27,250,000	0.61
	TOTAL	1,843,436,329	41.33

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• 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

Name of entity	Name of entity
FAR Ltd
ABN 41 009 117 293	Quarter ended (“current quarter”)
41 009 117 293	30 September 2016

Consolidated statement of cash flows	Current quarter $A’000	Year to date (9 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	- (4,662) - - (751) (347) - 31 - - - -	- (12,717) - - (2,283) (1,337) - 114 - - - -
	(5,729)	(16,223)
2. Cash flows from investing activities 2.1 Payments to acquire: (a) property, plant and equipment (b) tenements (see item 10) (c) investments (d) exploration and evaluation	(5) - - (8,442)	(45) - - (52,541)

• See chapter 19 for defined terms

1 September 2016

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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 (9 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	- - - - (5) - (2)	- - - - (20) - -
	(8,454)	(52,606)
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	- - - - - - - - -	60,000 - 2,728 (2,601) - - - - -
	-	(60,127)
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	66,279 (5,729) (8,454) - (1,588)	60,671 (16,223) (52,606) 60,127 (1,461)
	50,508	50,508

• See chapter 19 for defined terms 1 September 2016

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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)	42,404 104 - 8,000	55,912 367 - 10,000
	50,508	66,279
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 1.2 329 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
		Current quarter $A'000
		329
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
		Current quarter $A'000

• See chapter 19 for defined terms 1 September 2016

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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	7,000 - - 750 250 -
	8,000

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

• See chapter 19 for defined terms 1 September 2016

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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.

31 Oct 2016 Sign here: ............................................................ Date: ............................................. (Director/Company secretary) Peter Thiessen Print name: .........................................................

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

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