Annual Results

RNS Number : 7145N

Gulfsands Petroleum PLC

20 May 2015

 

Gulfsands Petroleum Plc

("Gulfsands" or the "Company")

Annual Results for the year ended 31 December 2014

20 May 2015

Gulfsands, the AIM listed oil and gas company (AIM:GPX) with activities in Syria, Morocco, Tunisia and Colombia, is pleased to announce its preliminary results for the year ended 31 December 2014.

Gulfsands Petroleum Plc Alastair Beardsall, Chairman	[phone]
Cantor Fitzgerald Europe Sarah Wharry David Porter	[phone]
First Energy Capital Jonathan Wright	[phone]

Our 2014 Highlights

·      2D and 3D seismic acquired in Morocco.

·      Gas discovery at LTU-1.

·      Group working interest Proved plus Probable Reserves of 73.5 mmboe.

·      Awarded Moulay Bouchta exploration licence in Morocco.

·      Syrian assets remain shut-in and secure during continuation of sanctions.

·      Total cash resources at year end of $19.4 million.

·      Cash available for use by the Group of $7.9 million.

·      Restricted cash balances of $11.5 million.

·      Convertible loan facility established.  $5 million drawn at year end and a further $5 million drawn in 2015 with interest accruing at 10% per annum.

Post Period Highlights

·      Drilling and testing of DRC-1 and DOB-1 prove up two further gas discoveries.

·      Continued significant reduction in office expenses.

Executive Chairman's Statement

Dear Shareholder,

During 2014 the Group made good progress in Morocco completing the acquisition and processing of 2D and 3D seismic on Fes and Rharb Centre respectively; we believe the new 3D seismic was instrumental in producing the drilling success that has followed on the Rharb Centre area; three gas discoveries have been made at LTU-1, DRC-1 and DOB-1. Discussions are underway with Office National des Hydrocarbures et des Mines (Morocco) ("ONHYM") and other local operators to start connecting these wells to local gas sales pipelines to enable the Group to enter into a gas sales contract to monetise the gas.

The Group's interests in Morocco are held in three licences, covering four permits. The Rharb Centre and Rharb Sud permits are included in one licence under which the outstanding work commitment of three exploration wells must be drilled before the period expires in November 2015. The Group is actively working with several parties who have expressed an interest in partnering Gulfsands in the Rharb Centre area.

The Moulay Bouchta licence was awarded to Gulfsands during 2014; it covers an area of some 2,800 km², including three abandoned legacy oil fields which demonstrate that there is an active hydrocarbon system present, likely to be oil prone. The initial two year exploration period runs to June 2016 during which time the Group must acquire 500km of new 2D seismic and reprocess some existing seismic data.   

The Fes licence in Morocco covers a large under-explored area where seismic acquisition, processing and interpretation are difficult. Gulfsands is working with a processing company with particular expertise to better image the subsurface using the existing seismic data set. We are optimistic that the end product will help us identify potential leads to be matured to drill-ready prospect status. The contract for Fes includes an, as yet, unfulfilled work obligation of an additional 350km of 2D seismic, 100km² of 3D seismic and three exploration wells that should be completed before 25 September 2015.

Gulfsands are in discussions with ONHYM regarding the outstanding work commitments on our licences for Rharb Centre, Rharb Sud and Fes, and we are hopeful we can agree a forward plan that allows Gulfsands to continue to explore and develop our interests in Morocco. 

In December 2013 the Group entered into a transaction with ADX Energy Limited ("ADX") whereby Gulfsands would acquire ADX's interest in the Chorbane licence in Tunisia for $1.75 million giving the Group 100% of the Chorbane licence. The transaction closed in 2014 and final consideration amounts were paid in early 2015.  The current exploration period under the licence runs to mid July 2015 and Gulfsands has submitted an application for a two year extension during which the work obligation of acquiring 200km 2D seismic and drilling one exploration well must be completed. If the application is successful the Group will look to farm-down its 100% interest in exchange for a carried work programme; if the application is unsuccessful, the licence will terminate.

The Group now holds 100% interest in its two Colombian blocks.  Joint venture arrangements with our former partners, Luna Energy Inc, were terminated in early 2015 under the terms of the original farm-out agreements.  Under the contracts for Llanos Block 50 and Putumayo Block 14, the Group has a minimum work obligation of acquiring approximately 100km of 2D seismic and drilling one exploration well on each block before the end of the current phase which has one and a half years to run to November 2016 for Llanos Block 50 and two and a half years to run to November 2017 for Putumayo Block 14. The Group is actively seeking farm-in candidates to share the cost of the exploration programme on these blocks.

In December 2014 the Group sold its interest in Gulfsands Petroleum USA, Inc., for $50,000, thus divesting itself of its operations in the US; under the transaction all staff associated with the US operations were transferred to the purchaser along with all abandonment obligations. This transaction brought to a close an association with North American assets that were the cornerstone of Gulfsands when it was first founded. 

Financial Overview

The Group posted a loss for the year of $16.1million, a significant reduction from the prior year, and completed exploration and evaluation asset investments of $21.0 million, predominantly in Morocco.  At year end the Group had total cash resources of $19.4 million of which $11.5 million was restricted; held as security for anticipated work programmes.  At the date of this report the Group had unaudited cash and cash equivalents of $3.0 million.

The Group entered into a Strategic Cooperation Agreement with Arawak Energy International Limited in November 2014, providing a framework so both parties could jointly identify, evaluate and acquire new ventures within a joint venture structure with a focus on the Middle East and North Africa ("MENA") region. Concurrently the Group entered into a $20 million Facility Agreement with Arawak Energy Bermuda Ltd ("Arawak") as a means of securing working capital. As of 9 January 2015 a total of $10 million had been drawn-down under the Facility Agreement. On 23 January 2015 however Arawak advised the Group that it was terminating the Strategic Cooperation Agreement and would not fund any further draw-downs under the Facility Agreement. Following this, in early March 2015, Arawak requested repayment of the $10 million drawn-down, and the interest that accrues at 10% per annum. The Group is in discussions with Arawak over the repayment of the monies owing.

The Group has material work obligations that must be completed under its various exploration licences and if these obligations are not met the Group may be forced to forfeit both its interest in these contracts and any sums of restricted cash lodged with host governments as guarantees for our performance of the minimum work obligations. The 2014 Financial Statements have been prepared on a going concern basis, and further details on this can be found in the Financial Review.

The Company is proposing to seek short term, unsecured, financing from some of its shareholders to use as working capital while it implements a new strategy for the Group's assets that is both financeable and sustainable in the current equity capital markets.  Longer term funding will probably be an equity raising or some combination of debt and equity. Further details will be announced before the Company's Annual General Meeting that is scheduled for 30 June 2015.  

Board and Management Changes

James Ede-Golightly and John Bell were appointed as Non-Executive Directors on 13 August 2014. James has extensive board experience with a focus on financial matters, whilst John has more than 20 years international experience in the management of oil and gas projects from exploration through to production. We welcome James and John and look forward to benefiting from their experience.

David Cowan and Michel Faure stepped down from the board on 30 June 2014 and 13 August 2014 respectively. David had served as a Non-Executive Director for more than eight years; his legal expertise has been a great asset during the growth and development of the Gulfsands business since joining the board in 2006. Michel was appointed a Non-Executive Director shortly after completing a long and successful career with Shell.  Whilst his tenure was just over a year, his contribution was assisting in country relations in Morocco and Tunisia. On behalf of the Board we thank both David and Michel for their respective contributions to the business.

In February 2015 Ken Judge left the Board and was served notice to terminate his executive services as Gulfsands legal counsel. 

On 13 April 2015 Mahdi Sajjad was removed from his role as the Company's Chief Executive. The Company has been advised by Mayer Brown International LLP, acting on behalf of Mr Sajjad, the action taken on 13 April 2015 constituted a material adverse change to Mr Sajjad's employment which he had not consented to; furthermore, Mr Sajjad has elected to treat his employment contract terminated on 8 May 2015 and claims certain payments are now due under his employment contract.  Mr Sajjad remains a Director of Gulfsands.

In April 2015 Andrew West stood down as Non-Executive Chairman and remains on the Board as a Non-Executive Director. Simultaneously I was appointed to the Board as a Director and Executive Chairman; I look forward to working with the Board, Management and staff in ensuring that the Group can operate within its means and fulfil the vision shared by many of our shareholders. 

Also in April 2015 Andrew Morris was appointed to the board as a Non-Executive Director. Andrew is Chairman of Madagascar Oil Limited and his career includes a period with the global accounting firm Ernst & Young.  We look forward to Andrew contributing on both technical and financial matters.

In April 2015 Alan Cutler resigned from his executive role as Director - Finance and Administration; it is expected that Alan will step down from the Board and leave the Company during the third quarter of 2015.

Outlook for 2015 and Beyond

The Group remains committed to maintaining its presence in Syria, and it considers its partnership with General Petroleum Corporation ("GPC") as a key element for the safe stewardship of Block 26 while the various sanctions prevent Gulfsands from a more active role.

In Morocco the portfolio of interests vary greatly in nature; early stage exploration in Fes where interpreting the seismic may unlock our understanding of the sub-surface, highly prospective exploration acreage in Rharb Sud and Moulay Bouchta located in an area known to be oil prone, and appraisal and development opportunities in Rharb Centre; however to capitalise on these opportunities the Group will need to secure new funds from both existing and new investors.

We shall seek to farm-out the assets we hold in Colombia and Tunisia ensuring we can benefit from any success but without being exposed to the full cost of exploration.

The Group faces many challenges over the coming months, including seeking extensions to licences and completing our work programmes, but above all, securing new funds sufficient to repay the Arawak loan facility and to provide the necessary working capital to allow progress to be made on some of our assets.

I would like to thank all our staff for the fortitude shown over the last twelve months and look forward to working with them in the future to develop Gulfsands into an oil & gas company we can all be proud to be part of.

Yours sincerely,

Alastair Beardsall

Executive Chairman

19 May 2015

Disclaimer

This results announcement contains certain forward-looking statements that are subject to the risk factors and uncertainties associated with the oil and gas exploration and production business.  Whilst the Group believes the expectations reflected herein to be reasonable in light of the information available to them at this time, the actual outcome may be materially different owing to a variety of factors including specific factors identified in this statement and other factors outlined in the Group's 2014 Annual Report.

Operations Review

Syria

Gulfsands is the operator of the Block 26 Production Sharing Contract ("PSC") and holds a 50% working interest in the PSC along with Sinochem. The Group is not presently involved in any production or exploration activities on Block 26 as force majeure has been declared in respect of the contract following the introduction of EU sanctions against Syria.

The Group has ensured that it remains compliant with all applicable sanctions in relation to Syria and intends to return to production and exploration activities as soon as permitted.

Block 26 covers an area of 5,414 km² in north east Syria and the PSC grants rights to explore, develop and produce hydrocarbons from all depths outside the pre-existing fields within the area and from the deeper stratigraphic levels below the pre-existing discovered fields. The final exploration period of the PSC was set to expire in August 2012 when force majeure was declared in December 2011. It is anticipated that an extension in the exploration period can be negotiated with the Syrian authorities to at least replace that period of time which was remaining when force majeure was declared. Rights to the benefits of production from discovered fields last for a minimum of 25 years from the date of development approval with extension thereto at the partners' option.

Under the Group's operatorship, two oil fields containing reservoirs of Cretaceous age have been discovered and developed within the PSC area, Khurbet East (2008) and Yousefieh (2010). During 2011 combined production from these fields reached a level of just under 25,000 barrels of oil per day ("bopd") before the impact of EU sanctions resulted in the curtailing of production levels. In addition, two further oil and gas discoveries with reservoirs of Triassic age have been identified beneath the Cretaceous aged oil producing reservoir in the Khurbet East field and within the Butmah and Kurrachine Dolomite formations. Development approvals for these discoveries were granted in 2011 and 2008 respectively. A further oil discovery was made late in 2011 by Gulfsands in the Cretaceous aged reservoirs at the Al Khairat exploration well, this discovery awaits further evaluation and development work.

The operation of these fields during the production phase is undertaken by Dijla Petroleum Corporation ("DPC"), a joint operating company formed between Gulfsands, Sinochem and the General Petroleum Corporation ("GPC") for this purpose, to which staff of both Gulfsands and GPC had previously been seconded. Since the introduction of EU sanctions on 1 December 2011 that identified GPC as a designated entity and the subsequent declaration of force majeure under the PSC, Gulfsands has had no involvement with the operations of DPC, and Gulfsands staff seconded to DPC have been withdrawn, leaving DPC under the management of GPC secondees.

Sanction Compliance

Gulfsands has taken extensive legal advice with respect to its obligations under the sanctions in place at the time and has liaised regularly with relevant regulators and generally acted cautiously to ensure it remains compliant with all relevant sanctions. The Board is determined to ensure that the Group's activities remain compliant and Management will continue to liaise closely with the relevant regulatory authorities to ensure this objective is achieved while continuing to keep GPC fully informed of the breadth and scope of restrictions on our activities as a result of continuing to comply with applicable sanctions.

Morocco

Gulfsands is the operator of a contiguous portfolio of onshore oil and gas exploration permits covering an area of approximately 7,210 km² in northern Morocco which incorporate proven petroleum systems. The Group has material equity interests in the three Contracts which govern the Moulay Bouchta, Fes, Rharb Centre and Rharb Sud permits.

Moulay Bouchta Contract

Contract expiry date:	First exploration phase, June 2016.
Minimum work obligation:	Acquisition of 500 km of 2D seismic data to be captured in a new survey; reprocessing  and interpretation of selected legacy 2D seismic lines and the existing 3D seismic data; and a legacy oil field reactivation study.
	Further details are provided in note 5 to the Preliminary Financial Statements.

In June 2014, the Group finalised agreements with Morocco's Office National des Hydrocarbures et des Mines ("ONHYM") and the government of Morocco for the award of the newly created Moulay Bouchta permit. Gulfsands acquired operatorship of the permit with a 75% participating interest while ONHYM retained a 25% participating interest, the attributable cost of which will be carried by Gulfsands upon the usual terms for such participation, through the exploration phase of the permit. The Moulay Bouchta permit encompasses an area of approximately 2,850 km² and is located to the north of the Group's Rharb Sud permit and extends eastwards to surround the western, northern and eastern boundaries of the Fes Block onshore in northern Morocco.

The Moulay Bouchta permit includes an area where the existence of a working petroleum system has been confirmed with the discovery and development of three oil fields, the most recent of which was the Haricha Field which had produced a total of 2.8 mmboe of oil and 4.2 bcf of gas when production ceased in 1990. A portion of the Moulay Bouchta permit area that surrounds and incorporates the Haricha Field has been the subject of a 175 km² 3D seismic survey by a previous operator. It is the intention of the Group to evaluate the potential for deeper and potentially larger structures containing Jurassic and Cretaceous aged reservoirs within the permit area. The permit is also believed to contain Tertiary aged reservoirs that may contain biogenic gas accumulations similar to those that occur in the adjacent Rharb Centre permit area, where commercially viable natural gas accumulations are found at depths of approximately 800-2,000 metres. 

Plans with respect to the minimum work obligation activities are at a well developed stage. The Group is pursuing options with respect to funding this work programme including bringing in industry partners.

Fes Contract

Contract expiry date:	September 2015.
Minimum work obligation:	Acquisition of an additional 350 km of 2D seismic data to be captured in a new survey; 100km² of new 3D seismic data; and drilling three exploration wells.
	Further details are provided in note 5 to the Preliminary Financial Statements.

2D seismic data has been acquired across the Fes permit area in a 650 km survey that commenced in 2013 and was completed in early 2014. Following this a conventional seismic processing of the data was undertaken that was completed in July 2014, however the results of this processing work did not yield the step change uplift in data quality and imaging that was anticipated.  

Work is now underway to further reprocess and upgrade these 2D data using a bespoke approach that is more specifically tailored to the geological fold and thrust belt setting in the Fes permit where the data was acquired. This additional seismic data reprocessing is being carried out in Calgary, Canada, by specialists using processing techniques not previously applied in Morocco. Initial results from the newly reprocessed data set indicates that it is yielding greater clarity in data imaging, which in turn offers opportunities to improve upon the geological interpretation of the data and on the reliability of mapping of key prospective potential oil bearing horizons. The results from the reprocessing work conducted to date have supported a more extensive and fulsome reprocessing of the 2D data acquired by Gulfsands during the course of 2015 which is currently underway. Once reprocessed, a further phase of re-interpretation and mapping work will be conducted in-house during 2015. 

Gulfsands are working closely with ONHYM to optimise the work programme in the complex geological area of the Fes permit, and an extension period to the current permit exploration period beyond September 2015 is currently being discussed with ONHYM. In parallel, the Group will pursue options for funding this work programme including bringing in industry partners.

Evaluation of Oil Prospectivity

The Moulay Bouchta, Rharb Sud and Fes permits are all considered prospective for oil, encompassing a working petroleum system incorporating three previously developed and produced shallow oil fields, and with many oil seeps encountered at surface.

Working closely with the technical staff of ONHYM, the Group's technical teams have been consolidating, updating and interpreting a significant amount of technical data that covers the three permits, and includes 2D and 3D seismic and well data from more than 850 legacy wells within the permits and surrounding area.

The Group's technical teams have identified leads on each of the Moulay Bouchta, Rharb Sud and Fes permits via 2D and 3D seismic data and/or legacy well data, and these will be subject to further evaluation in 2015, with the possibility that some may be the location of further acquisition of 2D seismic data by the Group.

Rharb Contract

Contract expiry date:	November 2015.
Minimum work obligation:	Drilling three exploration wells.
	Further details are provided in note 5 to the Preliminary Financial Statements.

A formal ten month extension to the Rharb exploration contract was granted by ONHYM in January 2015 extending the licence period to 9 November 2015.  The contract governs the Rharb Centre and Rharb Sud permits.

During 2014, Gulfsands drilled its fourth and fifth gas exploration wells in the Rharb centre permit area, both of which were located and drilled utilising Gulfsands 3D seismic survey data acquired in 2013 and processed in 2014. Both of these exploration wells resulted in gas discoveries. 

Well LTU-1, targeting the Lalla Yetou Updip prospect was spudded on 20 June 2014 and was drilled to a total depth of 1,182 metres.  Elevated gas readings obtained while drilling, as well as interpretation of wireline logs, indicated the presence of a gas bearing reservoir section of twelve metres thickness at the pre-drill target interval depth.  The main reservoir encountered appeared consistent with the pre-drill expectation of a turbidite distributary channel/fan complex, with laminated sand and silt layers and normal bed grading. A gas-to-water contact was interpreted in the well, based on gas shows and petrophysical data, at a depth approximately 13 metres below the reservoir section, also consistent with the pre-drill expectation.

After the conclusion of drilling and formation evaluation operations, the twelve metre reservoir section was perforated and a short production clean up flow period was undertaken. Within one hour of commencing the cleanup flow period, the well had unloaded the completion fluids and was producing 100% gas to surface with 0% bulk solids and water.  The estimated flow rate for the well, based on empirical calculation methods, was approximately 6.6 million standard cubic feet per day ("mmscfpd") on a 28/64 inch choke.  After the clean up flow period the well was shut in and is now temporarily suspended as a future gas producer.

The LTU-1 gas discovery can be tied back to the area gas export pipeline system, and related civil works involving the installation of production facilities and connecting flow trunk lines are currently being evaluated. 

Well DRC-1, targeting the Dardara South East gas exploration prospect and located in the north-west corner of the 3D seismic survey area, was spudded on the 19 December 2014, and drilled to a total depth of 1,153 metres.  The well encountered the primary reservoir target interval on prognosis at a depth of 875 metres. Significantly elevated gas readings obtained while drilling, as well as interpretation of geological samples and wireline logs, indicate the presence of a gas bearing sandstone reservoir section of excellent quality.

Detailed petrophysical evaluation of DRC-1 wireline logs yielded an interpretation indicating a 53 metres gross thickness of excellent quality reservoir sand between 875-928 metres, with a net gas bearing sand thickness of 16 metres, evaluated average gas saturation of 65% and average porosity of 32%. A gas-to-water contact was observed in the well at approximately 895 metres as evidenced by wireline log and formation pressure data.

 
Due to the presence of over-pressured shales in the lower section of the well-bore, and in order to ensure that the well-bore integrity was maintained for wireline logging operations, the well was not deepened further into a secondary target objective and beyond that to the original planned Total Depth ("TD") of 1,280 metres. Instead the well was cased, cemented, and perforated over the interval 876-884 metres, and a completion run in order to perform a flow test.

Following an initial two hour well clean-up flow period, the well was fully unloaded of completion fluids to a 100% gas stream. During two subsequent flow periods of six hours and eight hours respectively the well flowed first at an average gas rate of 7.1 mmscfpd on a 32/64^th inch choke and then later at an average rate of 9.4 mmscfpd on a 40/64^th inch choke. The well flowed with no associated formation water production or sand production in both flow periods. Following the second flow period the well was shut-in for a pressure survey in order to evaluate reservoir information and connected gas volumes, after which the well was suspended as a future gas production well.

In the Dardara area in addition to encountering a potentially highly productive net gas bearing interval of 16 metres, the DRC-1 well result indicates additional gas exploration potential to exist in adjacent areas and fault blocks.

The DOB-1 well was spudded in January 2015 and drilled to a TD of 1,140 metres Measured Depth ("MD") where it encountered the primary reservoir target interval on prognosis at a depth of approximately 808 metres MD. Significantly elevated gas readings obtained while drilling, as well as interpretation of geological samples and wire line logs, indicated the presence of a gas bearing sandstone reservoir section of excellent quality. Detailed petrophysical evaluation of wireline logs over the primary target yielded an interpretation indicating a 4.2 metres gross sand thickness, with a net sand thickness of 3.7 metres and evaluated average gas saturation of 70% and average porosity of 34%.

The well was subjected to a flow testing and pressure survey period for evaluation of well flow performance and connected gas volumes. During initial clean up flow operations over this reservoir, the well produced natural gas at an estimated rate in excess of 10 million mmscfpd on a 48/64th inch choke setting. During subsequent multi-rate flow testing, a stable flow of 6.2 mmscfpd was established for a period of 4 hours on a 32/64th inch choke setting, with a final wellhead flowing pressure of 1,084 psi. No formation water was detected in the gas production stream during testing operations.

The secondary reservoir target interval for the well was encountered at a depth of approximately 1,075 metres MD.  Significantly elevated gas readings were encountered over the interval 1,075 -1,127 metres MD. However, problems with well bore integrity above this interval prevented further evaluation of the potential of this deeper potential reservoir at this time.  The Group is reviewing options for evaluating this reservoir in future operations.

Subsequent to these drilling operations the Group have been conducting a detailed technical assessment over the DOB-1 and DRC-1 gas discoveries that will include the identification of potential locations for further drilling in the near vicinity of these discoveries.

The Group have additionally been working with its partner, ONHYM, on strategies to commercialise the discoveries made. These discussions are ongoing at the date of this report.

Following the drilling of DOB-1, Gulfsands has three remaining well commitments across the Rharb concession including the Rharb Sud permit, to be drilled by the end of the licence period on 9 November, 2015. The Group are working closely with ONHYM with respect to these work obligations and the commercialisation of discoveries made on this permit. In parallel, the Group are considering options for funding this work programme and the development of discoveries which may include bringing in industry partners.

Tunisia

Gulfsands has a 100% interest in the operated Chorbane exploration permit onshore Tunisia covering approximately 1,942km².

Contract expiry date:	July 2015.
Minimum work obligation:	Drilling one exploration well.
	Further details are provided in note 5 to the Preliminary Financial Statements.

The Tunisian Authorities (Comité Consultatif des Hydrocarbures or "CCH") have approved the transfer of all of ADX Energy Limited's remaining legal interest (30%) in the Chorbane permit, onshore Tunisia, to Gulfsands Petroleum Tunisia Limited, a wholly owned subsidiary of the Company. The Company's subsidiary is Operator of the Chorbane permit and is now legal owner of a 100% interest in the permit.

The current exploration period under the licence runs to mid July 2015 and Gulfsands has submitted an application for a two year extension during which the work obligation of acquiring 200km 2D seismic and drilling one exploration well must be completed. If the application is successful the Group will look to farm-down its 100% interest in exchange for a carried work programme; if the application is unsuccessful, the licence will terminate.

Colombia

Gulfsands has Exploration and Production Contracts ("E&P Contracts") over two onshore contract areas, Putumayo Block 14 ("PUT 14") and Llanos Block 50 ("LLA 50").

Llanos Block 50
Contract expiry date:	First exploration phase, November 2016.
Minimum work obligation:	Acquisition of an additional 93 km of 2D seismic data to be captured in a new survey; and drilling one exploration well.
	Further details are provided in note 5 to the Preliminary Financial Statements.
Putumayo Block 14
Contract expiry date:	First exploration phase, November 2017.
Minimum work obligation:	Acquisition of an additional 103 km of 2D seismic data to be captured in a new survey; and drilling one exploration well.
	Further details are provided in note 5 to the Preliminary Financial Statements.

The Group continues to undertake the preliminary studies required to be completed prior to the commencement of either 2D or possibly exploration-oriented 3D seismic acquisition programmes on the contract areas. Discussions with other operators in the Putumayo and Llanos areas and seismic contractors active in these areas have commenced with a view to co-ordinating and sharing logistics as well as optimising parameters for the seismic programmes being planned on both contract areas.

The next phase of the work programme on PUT 14 includes a "Consulta Previa", being a consultation with local indigenous and tribal peoples regarding the implementation of any project that may have an impact on their culture, heritage, social - economical conditions and environment.  This Consulta Previa has an expected duration of six months. In parallel, a PMA "Plan de Manejo Ambiental", or Environmental Management Plan, is required to be prepared across the whole contract area, completion of which will allow the commencement of a seismic survey.  Operators in nearby contract areas in the Putumayo basin have successfully utilised 2D and 3D seismic data and interpretation methods generating multiple discoveries in the area.

On LLA 50, a MMA "Medidas Manejo Ambiental", or Environmental Management Measures, is being prepared across the whole contract area, completion of which will allow the commencement of a seismic survey.  The annual weather window (dry season) for seismic operations in this region is quite narrow, typically restricting seismic acquisition to the period from mid-December to mid-April. The LLA 50 contract area is located within the proven and productive Llanos basin in eastern Colombia.

The Group is currently considering divestment or farm-down options for its interests in the contract areas prior to any significant financial commitment with respect to further exploration work.

Reserves Report

Reserves

Reserves are categorised into Proved, Probable and Possible reserves in accordance with the 2007 Petroleum Resources Management classification system ("PRMS") of the Society of Petroleum Engineers ("SPE"). Definitions for Proved, Probable and Possible reserves are contained in the Glossary.

The Group's Reserves are based on estimates made by Gulfsands' Technical teams which are approved by Management and then reviewed by independent petroleum engineers from external parties. External reviews have been performed for the Group by Senergy (GB) Limited ("Senergy") since 2009.

Summary of Reserves

Working interest reserves in Syria represent the proportion, attributable to the Group's 50% participating interest, of forecast future hydrocarbon production during the economic life of the Block 26 PSC, including the share of that production attributable to General Petroleum Corporation ("GPC").  In assessing the Group's Reserves attributable to Syria Block 26 it has been assumed that the force majeure condition is lifted with effect from 1 January 2016 and Gulfsands resumes its role as operator. It should be noted that there remain significant uncertainties with respect to the timing of the Group's re-entry into Syria and the conditions encountered upon its return.

Reserves attributable to the Group's US business, which was divested during 2014, are no longer recorded. 

Working interest basis

	Syria		US			Group total
	Oil	Gas		Oil	Gas	Oil	Gas	Oil & Gas
	mmbbl	bcf		mmbbl	bcf	mmbbl	Bcf	mmboe
As at 31 December 2014
Proved	38.5	11.0		0.0	0.0	38.5	11.0	40.3
Probable	29.7	20.5		0.0	0.0	29.7	20.5	33.2
Proved and Probable	68.2	31.5		0.0	0.0	68.2	31.5	73.5
Possible	41.8	35.5		0.0	0.0	41.8	35.5	47.7
Proved, Probable and Possible	110.0	67.0		0.0	0.0	110.0	67.0	121.2

Movements in Proved and Probable reserves during year

As at 31 December 2013	68.9	33.0	1.0	2.0	69.9	35.0	75.8
Discoveries and additions	0.0	0.0	0.0	0.0	0.0	0.0	0.0
Disposals	0.0	0.0	(0.9)	(1.9)	(0.9)	(1.9)	(1.2)
Revisions	(0.5)	(1.5)	0.0	0.0	(0.5)	(1.5)	(0.8)
Less estimated production	(0.2)	(0.0)	(0.1)	(0.1)	(0.3)	(0.1)	(0.3)
At 31 December 2014	68.2	31.5	0.0	0.0	68.2	31.5	73.5
Represented on an entitlement basis At 31 December 2014	29.5	16.5	0.0	0.0	29.5	16.5	32.3

NB Certain figures may not add up due to roundings.

"Oil" includes condensate and NGLs.

Gas is converted to mmboe at the conversion factor 1 bcf = 0.1667 mmboe.

Resources

The Group's Resources are based on estimates made by Gulfsands' Technical teams which are approved by Management and then reviewed by independent petroleum engineers from external parties. External reviews have been performed for the Group by Senergy since 2009.

Summary of Contingent Resources

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by the application of development projects, but are not currently considered to be commercially recoverable due to one or more contingencies. Contingent Resources are further categorised by the SPE into 1C, 2C and 3C according to the level of uncertainty associated with the estimates.

In accordance with the 2007 SPE PRMS, a guideline risk factor should be stated associated with the Contingent Resources quoted for each category; the risk factor indicates the likelihood that the Group will ultimately commercially develop the resource. The risk factor considers all technical and non-technical factors that are impacting or are likely to impact on the likelihood of development, and is termed the "Chance of Development".

Unrisked working interest basis

As at 31 March 2015

						Risk factor
		Constituent	1C	2C	3C	(Chance of development)
Syria Block 26
(Working interest 50%)
Al Khairat discovery		Oil, mmbbl	2.9	12.0	45.7	30%
Morocco Rharb Centre permit
(Working interest 75%)
Beni Fdal discovery	Sales Gas, bcf		0.3	0.7	1.9	50%
Douar Nouaoura discovery	Sales Gas, bcf		0.4	1.3	4.3	20%
Lalla Yetou Updip discovery	Sales Gas, bcf		0.8	2.0	4.3	90%
Dardara Southeast discovery	Sales Gas, bcf		1.6	4.7	13.9	90%
Douar Ouled Balkhair discovery	Sales Gas, bcf		0.2	0.6	1.9	90%
	Total, bcf		3.3	9.3	26.3

NB Certain figures may not add up due to roundings.

"Oil" includes condensate and NGLs.

Gas is converted to mmboe at the conversion factor 1 bcf = 0.1667 mmboe.

Summary of Prospective Resources

Prospective Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. They are further categorised by the 2007 SPE PRMS into Low, Best and High estimates. The quoted Low, Best and High estimates are the 90% probability ("P90"), 50% probability ("P50") and 10% probability ("P10") values respectively derived from probabilistic estimates generated using a Monte Carlo statistical approach.

In accordance with the 2007 SPE PRMS, a guideline risk assessment should be provided associated with the Prospective Resources quoted for Low, Best and High estimate categories. The risk assessment here is the Chance of Discovery; the additional risk assessment relating to the Chance of Development is not normally quantified at this level of resource classification.

Unrisked working interest basis

As at 31 March 2015

						Risk factor
	Constituent		Low	Best	High	(Chance of discovery)
Morocco Rharb Centre permit
(Working interest 75%)
Upper Miocene prospects	Sales Gas, bcf		3.0	7.4	16.3	35-48%
Upper Miocene leads	Sales Gas, bcf		6	17	37	Medium-High
Morocco Rharb Sud permit
(Working interest 75%)	Oil and Sales Gas, mmboe
Jurassic leads			1	11	66	Low-Medium
Morocco Moulay Bouchta permit
(Working interest 75%)	Oil and Sales Gas, mmboe
Jurassic leads			1	11	75	Low-Medium
Morocco Fes permit
(Working interest 50%)	Oil and Sales Gas, mmboe
Jurassic leads			21	478	2,250	Low-Medium
Morocco total	mmboe		24	504	2,400
						Risk factor
		Constituent	Low	Best	High	(Chance of discovery)
Tunisia Chorbane permit
(Working interest 100%)
Sidi Agareb prospect Eocene / Upper Cretaceous		Oil, mmbbl	8	27	63	9%-25%
Lafaya Deep & Sidi Daher prospects Jurassic leads		Sales Gas, bcf	21	103	398	Low
Tunisia total		mmboe	12	44	129

NB Certain figures may not add up due to roundings.

"Oil" includes condensate and NGLs.

Gas is converted to mmboe at the conversion factor 1 bcf = 0.1667 mmboe.

Financial Review

Selected operational and financial data

			Year ended 31 December 2014	Year ended 31 December 2013
			$' 000	$' 000
General administrative expenses			(5,469)	(9,408)
Exploration costs written-off			(6,040)	(12,301)
Loss from continuing operations			(12,113)	(25,382)
Loss for the year			(16,091)	(26,757)
Net cash used in operating activities by continuing operations			(3,799)	(8,611)
E&E cash expenditure			(26,987)	(17,302)
Cash and cash equivalents			7,907	33,824
Restricted cash balances			11,514	19,138

The loss for the year was $16.1 million (2013: $26.8 million), consisting of a loss from continuing operations for the year of $12.1 million (2013: $25.4 million) and a loss from discontinued operations for the year of $4.0 million (2013: $1.4 million).  The loss from discontinued operations related to the US operations which were disposed of in December 2014.  Under the requirements of IFRS 5, the 2013 comparatives for discontinued operations have been reclassified in the Income Statement.  

General administrative expenses fell by $4.0 million during the year.  Office expenses after partner recoveries reduced by $1.7 million whilst a reduction in depreciation and an increase in office expenses capitalised, further reduced general administrative expenses by $2.3 million.

Exploration and evaluation asset write-offs decreased in the year to $6.0 million (2013: $12.3 million).  2014  write-offs consisted of $5.2 million in respect of Moroccan E&E assets and $0.8 million in respect of Tunisian E&E assets.  2013 write-offs largely reflected three unsuccessful exploration wells drilled on the Rharb Centre permit.

The carrying value of exploration and evaluation assets on the Balance Sheet increased to $53.0 million at 31 December 2014 (31 December 2013: $37.1 million), predominantly due to the substantial investment in Morocco during the year including  the drilling of the successful LTU-1 and DRC-1 gas wells. 

The Group continues to value its investment in its Syrian interest at $102.0 million.

Total unrestricted cash and cash equivalents reduced by $25.9 million in the year to $7.9 million at 31 December 2014 (31 December 2013: $33.8 million).  Restricted cash balances reduced by $7.6 million to $11.5 million (31 December 2013: $19.1 million).

Operating performance

			Year ended 31 December 2014	Year ended 31 December 2013
General administrative expenses			$' 000	$' 000
Office expenses after partner recoveries			(12,163)	(13,815)
Depreciation and amortisation			(602)	(1,124)
Office expenses capitalised			7,296	5,531
General administrative expenses			(5,469)	(9,408)

Gulfsands made significant progress in 2014 to further reduce its operating cost base with general administrative expenses reducing to $5.5 million in the year (2013: $9.4 million). $1.7 million of the reduction represents a reduction in office expenses after partner recoveries.   In addition to this: a reduction in depreciation; and the progression in the Group's business model toward operatorship of its assets as well as increased operational activity, particularly in Morocco, resulting in increased amounts capitalised, further reduced general administrative expenses by $2.3 million in the year. 

Exploration write-offs for the year totalled $6.0 million (2013: $12.3 million), of which $5.2 million relates to Moroccan operations and $0.8 million relates to Tunisian operations.  Expenditure written-off in relation to Moroccan operations included $1.5 million of expenditure related to 2014 expenditures on the wells drilled in the first phase of drilling on the Rharb Centre permit, which commenced in October 2013 and completed in January 2014.  These wells were deemed non-commercial and plugged and abandoned.  A further $3.7 million of expenditure, on activities that were unsuccessful, was written-off in the year.  

The Group reported a reduced loss before tax from continuing operations of $12.1 million (2013: $25.4 million) for the year. In addition to the reduction in general administrative expenses and reduced exploration write-offs in the year, this improved performance also reflects the incurrence of exceptional one-off Syrian inventory write-offs and impairments in 2013 of $2.9 million. 

The Group sold its investment in its wholly-owned US subsidiary, Gulfsands Petroleum USA, Inc. ("GPUSA"), to Hillcrest Resources Ltd ("Hillcrest") for a consideration of $50k.  As part of the sale and purchase agreement the intercorporate debt owed by GPUSA to the Gulfsands Group was also assigned to Hillcrest.  The sale of the investment in GPUSA means all of the Group's interests in oil and gas licences in the Gulf of Mexico as well as their related decommissioning liabilities and amounts held in escrow to guarantee those decommissioning liabilities have been disposed of.  The transaction was completed on the 18 December 2014.  Losses from discontinued operations in the year were $4.0 million (2013: $1.4 million) consisting of a loss on disposal of $2.5 million in addition to the loss for the eleven months to disposal generated by the US operations of $1.5 million (2013 twelve months loss: $1.4 million).   The results of the discontinued US operations have been consolidated to 30 November 2014 which is treated as the effective completion date; the results for the eighteen days to 18 December 2014 are considered not material to the Group.  Under the requirements of IFRS 5, the 2013 comparatives for the discontinued operations have been reclassified in the Consolidated Income Statement and Consolidated Cash Flow Statement.  

The Group reported a reduced loss for the year of $16.1 million (2013: $26.8 million). 

Balance sheet

Property, plant and equipment reduced as the Group's producing Gulf of Mexico oil and gas assets were disposed of in December 2014 as part of the sale of the Group's investment in GPUSA.

The Group continued to build on its exploration portfolio and was awarded the Moulay Bouchta contract, onshore Morocco, in April 2014.  At 31 December 2014, intangible exploration and evaluation assets are held at a net book value of $53.0 million (31 December 2013: $37.1 million) of which $46.6 million relates to cumulative expenditure capitalised against Moroccan permits (31 December 2013: $31.6 million).  Capital expenditures during the year totalled $21.0 million (2013: $46.5 million), on an accrued basis, including $7.9 million of drilling related costs incurred in respect of successful drilling on the Rharb Centre permit.  The drilling of LTU-1 commenced on 20 June 2014 and a gas discovery made.  Drilling of the DRC-1 well commenced on 19 December 2014. This well, was being tested at year end and declared a discovery post year end.  Drilling continued into the first quarter of 2015 with a further well, DOB-1, also declared a discovery post year end. 

Other significant exploration expenditures incurred in the year for Moroccan operations included: $1.1 million of Rharb Centre 3D seismic costs with processing completed in the first quarter of 2014; $2.7 million of 2D seismic costs over the Fes area with the acquisition and processing completing in the first quarter of 2014; and $1.2 million for the first phase of drilling in Rharb Centre, with the final well of three, BFD-2, completing in January 2014.  As a result of the increased operational activity during the year, $7.3 million of operations office expenses were capitalised against the Moroccan, Tunisian and Colombian contracts.  Exploration write-offs for the year totalled $6.0 million (2013: $12.3 million); the previous year included the cost of the three unsuccessful wells drilled.  

The fair value of the Group's net investment in its Syrian interests remains unchanged at $102.0 million.  The Board reconsidered the valuation as at 31 December 2014, and it is their view that there has been little significant change to the circumstances and status of the Group's Syrian interests.  The Board are still unable to provide a firm view as to the eventual outcome and the timing of resolution of the situation in Syria that would lead to the EU lifting sanctions against Syria, allowing Gulfsands to return, however, they continue to consider that its position in respect of its interests remains strong and all indications are that Syrian authorities expect Gulfsands and its partner to return to operational control of their interests in accordance with the terms of the PSC as soon as circumstances permit.  The carrying value of the Syrian interest continues to be supported by the Group's valuation model based on the estimated future cash flows that could be generated from the Group's remaining entitlement reserves in Block 26 in Syria.  Due to the recent significant fall in oil price the Board has decided that it would be more appropriate to use the forward Brent oil price curve to value forecast production from the assets, with an assumption of 2% price inflation beyond the end of the quoted curve.  This would have a significant impact on the value of near-term production but, because the valuation model includes an assumption that the recommencement of production is deferred for five years, the actual impact on forecast revenues is limited.  The Board continues to hold the view that its current valuation of $102.0 million, representing 25% of the base "value in use" calculation for its Syrian interests, remains fair and appropriate.

Trade and other receivables have decreased during the year to $1.0 million (31 December 2013: $3.5 million).  This is predominantly due to the recovery of historic balances due from oil and gas partners totalling $1.3 million. 

Current trade and other payables at 31 December 2014 have decreased significantly from 2013 year end to $5.9 million (31 December 2013: $15.2 million) predominantly as a result of the timing of drilling operations in Morocco with substantially lower activity at the 2014 year end than the previous year end.

Decommissioning provisions relate to abandonment and restoration provisions on the Rharb Centre Moroccan wells and total $1.0 million at 31 December 2014.  Decommissioning provisions at 31 December 2013 totalled $13.2 million and related to the US Gulf of Mexico assets which have been disposed of in December 2014.

On 19 November 2014, the Group announced the closing of a $20.0 million convertible loan facility with Arawak Energy Bermuda Ltd ("Arawak") and subsequently drew down the first $5.0 million tranche on 25 November 2014.  The loan bears interest at 10% per annum in addition to a commitment fee of 3% per annum on the available facility, both of which are rolled up quarterly into the loan balance.  The loan matures on the 30 November 2017 and is repayable in full on the maturity date.  The convertible loan is a hybrid financial instrument and the option to convert is an embedded derivative.  The conversion option has been valued at the date of the first draw-down and at the year end using a Black-Scholes model and the valuation considered immaterial for separate recognition in the Balance Sheet.  Subsequent to the year end a further $5.0 million was drawn-down.  In early March Arawak requested early repayment of the outstanding loan amount.

Cash flow

Operating cash outflow from continuing operations was substantially reduced in the year to $3.8 million (2013: $8.6 million) largely as a consequence of the reduction in general administrative expenses.

Investing cash outflow from continuing operations during the year totalled $24.0 million (2013 $45.6 million).  This predominantly consists of: $27.0 million of exploration expenditure inclusive of $24.8 million spent on Moroccan operations and $1.75 million being placed as security with respect to the newly awarded Moulay Bouchta licence obligations; partially offset by restricted cash balances released during the year totalling $6.5 million.

The total cash outflow for the US discontinued operation in the year was $2.8 million (2013: $3.0 million).  This consisted of: cash outflows for investing activities of $5.0 million (2013: $3.7 million); cash disposed of as part of the disposal of $0.2 million; partially offset by cash generated by production operations of $2.4 million (2013: $0.7 million).  The improvement in cash generated by operating activities was due to the increased revenues from Eugene Island Block 32 resulting from the work-over of well #33 and the sidetrack of well #30.  These work-overs and sidetracks were also the reason for the increase in investing cash outflows in 2014.

The total decrease in cash and cash equivalents during the year was $25.9 million (2013: $57.2 million).   

Financial position

The Group had total unrestricted cash and cash equivalents of $7.9 million (31 December 2013: $33.8 million).  

Restricted cash balances at the end of the period (which are presented as long-term financial assets in the Balance Sheet) totalled $11.5 million, and represent funds securitised as collateral in respect of future work obligations - principally in respect of the Group's Moroccan interests.  Restricted cash balances have decreased by $7.6 million during the year as a result of: a release of $6.5 million due to partial completion of the Moroccan work programmes, disposal of the $2.9 million US guarantees as part of the disposal of the investment in GPUSA, all partially offset by a new $1.75 million deposit being placed for future work obligations relating to the award of the Moulay Bouchta licence.  The restricted cash balances will continue to be released to the Group as work programmes are completed with $2.5 million to be repaid to a third party upon release. 

Going concern

The Consolidated and Company Financial Statements have been prepared on the going concern basis which has been approved by the Board. The basis on which the Board has reached this decision is as follows:

As at the date of this report, the Group has cash balances immediately available to it totalling approximately $3.0 million with net current liabilities of approximately $2.6 million and ongoing costs currently approximating to $1.0 million per month. Restricted cash balances and the work commitments to which they relate are described in note 5 to the Preliminary Financial Statements. Additionally, the Group has an outstanding loan of $10 million from Arawak, which they have requested be repaid. This loan is described in note 7 to the Preliminary Financial Statements.  Early repayment will cause a minimum of $1 million of interest and fees to also become payable.

The Board is in the process of actioning its strategy for each asset and these strategies are laid out in the Operations Review of this Report. This includes substantially reducing its costs whilst, farming-down, divesting or otherwise rationalising certain interests and the associated work commitments. In parallel the Group is actioning a financing strategy which includes accessing a short-term working capital loan from existing shareholders to provide the Group with time to progress a more significant financing exercise. The Board has received indications from certain of its shareholders of a willingness to contribute to such a working capital loan. Shortly, the Board will develop and communicate its longer-term financing strategy which should allow the Group to achieve the following:

·      repayment of the Arawak facility;

·      rationalisation of existing minimum work commitments;

·      further appraisal and exploitation of selected assets;

·      working capital to provide stability for the medium term.

As stated elsewhere, the Group may not finance all its work commitments itself but will look to bring in partners to reduce the Group's net exposure to such commitments to a level that the Board considers sustainable and financeable or, alternatively, it will divest itself of assets as necessary.

Based upon its experience and ongoing discussions with existing shareholders and potential partners, the Board is confident that the Group will be able to access appropriate resources to finance the strategy that it is developing.

Notwithstanding the confidence that the Board has in its ability to stabilise and finance the Group's re-shaped business, the Directors, in accordance with FRC guidance in this area, conclude that at this time there is material uncertainty that such finance can be procured and failure to do so might cast significant doubt upon the Company's and the Group's ability to continue as a going concern and that the Company and the Group may therefore be unable to realise their assets and discharge their liabilities in the normal course of business. Such scenario could impact upon the carrying value of intangible exploration and evaluation assets and on the recoverability of certain restricted cash amounts, held in escrow to support guarantees of performance of minimum work obligations.  See further details in note 5 to the Preliminary Financial Statements.

However, following completion of a review of the going concern position of the Company and Group at the meeting of the Board of Directors on 18 May 2015, including the uncertainties described above, the Board has concluded that, with current consolidated cash and cash equivalents totalling $3.0 million and taking into account both the revised strategy of farming-down or divesting assets and new financial resources that the Board might reasonably expect to become available, the Company and the Group will have sufficient resources to continue in operational existence for the foreseeable future, a period not less than twelve months from the date of approval of this Annual Report. Accordingly, the Directors consider it appropriate to continue to adopt the "going concern basis" in preparing these Financial Statements.

Consolidated Income Statement

for the year ended 31 December 2014

	Notes	2014 $'000	2013 $'000
Continuing Operations
General administrative expenses		(5,469)	(9,408)
Share-based payments		(56)	(514)
Total administrative expenses		(5,525)	(9,922)
Exploration costs written-off	5	(6,040)	(12,301)
Syrian inventory provision/ write-off		-	(2,905)
Other Syrian adjustments		(202)	(383)
Operating loss		(11,767)	(25,511)
Foreign exchange (losses)/ gains		(218)	89
Bank fees and charges		(76)	(49)
Loan facility finance cost	7	(70)	-
Net interest income		18	89
Loss before taxation from continuing activities		(12,113)	(25,382)
Taxation from continuing activities		-	-
Loss for the year from continuing operations		(12,113)	(25,382)
Discontinued Operations
Loss for the year from discontinued operations	2	(3,978)	(1,375)
Loss for the year attributable to owners of the parent company		(16,091)	(26,757)
Loss per share from continuing operations (cents):
Basic and diluted	3	(10.28)	(21.54)
Loss per share attributable to the owners of the parent company (cents):
Basic and diluted	3	(13.65)	(22.70)

There are no items of comprehensive income outside of the Income Statement.

Consolidated Balance Sheet

as at 31 December 2014

	Notes	2014 $'000	2013 $'000
Assets
Non-current assets
Property, plant and equipment	4	285	12,893
Intangible assets	5	53,352	37,558
Long-term financial assets		11,514	19,138
Investments	6	102,000	102,000
		167,151	171,589
Current assets
Inventory		2,361	2,247
Trade and other receivables		1,028	3,542
Cash and cash equivalents		7,907	33,824
		11,296	39,613
Total assets		178,447	211,202
Liabilities
Current liabilities
Trade and other payables		5,882	15,245
Provision for decommissioning		580	2,573
		6,462	17,818
Non-current liabilities
Trade and other payables		6,178	6,155
Provision for decommissioning		397	10,578
Loan facility	7	4,855	-
		11,430	16,733
Total liabilities		17,892	34,551
Net assets		160,555	176,651
Equity
Capital and reserves attributable to equity holders
Share capital		13,131	13,131
Share premium		105,926	105,926
Merger reserve		11,709	11,709
Treasury shares		(11,502)	(11,502)
Retained profit		41,291	57,387
Total equity		160,555	176,651

Consolidated Statement of Changes in Equity

for the year ended 31 December 2014

	Share capital $'000	Share premium $'000	Merger reserve $'000	Treasury shares $'000	Retained profit $'000	Total equity $'000
At 1 January 2013	13,131	105,926	11,709	(11,619)	83,776	202,923
Options exercised	-	-	--	117	(148)	(31)
Share-based payment charge	-	-	-	-	516	516
Loss for 2013	-	-	-	-	(26,757)	(26,757)
At 31 December 2013	13,131	105,926	11,709	(11,502)	57,387	176,651
Options exercised	-	-	--	-	(61)	(61)
Share-based payment charge	-	-	-	-	56	56
Loss for 2014	-	-	-	-	(16,091)	(16,091)
At 31 December 2014	13,131	105,926	11,709	(11,502)	41,291	160,555

The merger reserve arose on the acquisition of Gulfsands Petroleum Ltd and its subsidiaries by the Company by way of share-for-share exchange in April 2005, in conjunction with the flotation of the Company on the Alternative Investment Market of the London Stock Exchange.

Consolidated Cash Flow Statement

for the year ended 31 December 2014

	Notes	2014 $'000	2013 $'000
Cash flows from operating activities
Operating loss from continuing operations		(11,767)	(25,511)
Depreciation and amortisation	4&5	602	877
Exploration costs written-off	5	6,040	12,301
Other Syrian adjustments		202	383
Share-based payment charge		56	514
Syrian inventory provision / write-off		-	2,905
Decrease/ (increase) in receivables		1,598	(527)
(Decrease) / increase in payables		(254)	318
Foreign exchange (losses) / gains		(218)	89
Bank fees		(76)	(49)
Interest received		18	89
Net cash used in operating activities by continuing operations		(3,799)	(8,611)
Net cash generated by operating activities of discontinued operations	2	2,347	724
Total net cash used in operating activities		(1,452)	(7,887)
Investing activities
Acquisition of subsidiary undertaking		-	(17,103)
Exploration and evaluation expenditure		(26,987)	(17,302)
Inventory purchased		(1,420)	(2,247)
Other capital expenditures		(340)	(630)
Change in restricted cash balances		4,750	(8,270)
Net cash used in investing activities by continuing operations		(23,997)	(45,552)
Net cash used in investing activities by discontinued operations	2	(5,011)	(3,688)
Total net cash used in investing activities		(29,008)	(49,240)
Financing activities
Loan draw-down	7	5,000	-
Transaction costs paid on loan facility	7	(215)	-
Other payments in connection with options exercised		(61)	(31)
Net cash provided by / (used in) financing activities of continuing operations		4,724	(31)
Net cash used in financing activities of discontinued operations	2	-	-
Total net cash provided by / (used in) financing activities		4,724	(31)
Cash disposed as part of disposal of discontinued operations	2	(181)	-
Decrease in cash and cash equivalents		(25,917)	(57,158)
Cash and cash equivalents at beginning of year		33,824	90,982
Cash and cash equivalents at end of year		7,907	33,824

Condensed Notes to the Preliminary Financial Statements

for the year ended 31 December 2014

General information

Gulfsands Petroleum plc is a public limited company listed on the Alternative Investment Market ("AIM") of the London Stock Exchange and incorporated in the United Kingdom. The principal activities of the Company and its subsidiaries ("the Group") are that of oil and gas production, exploration and development.  The address of the registered office is 1 America Square, Crosswall, London, United Kingdom, EC3N 2SG. This preliminary announcement was authorised for issue in accordance with a resolution of the Board of Directors on 19 May 2015.

The financial information for the year ended 31 December 2014 set out in this announcement does not constitute statutory accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 December 2013 were approved by the Board of Directors on 3 April 2014 and delivered to the Registrar of Companies and those for 2014 will be delivered following the Company's Annual General Meeting ("AGM").

While the financial information included in this preliminary announcement has been prepared in accordance with International Financial Reporting Standards ("IFRS"), this announcement does not itself contain sufficient information to comply with IFRS. The Company expects to distribute the full financial statements that comply with IFRS in early June 2015.

Audit Report

The financial information set out above does not constitute the Company's statutory accounts for the year ended 31 December 2014 or 2013, but is derived from those accounts. The Auditor has reported on those accounts; its reports were unqualified, but did contain two emphasis of matter paragraphs in 2014 in respect of: going concern, on which further details are available below and in the Financial Review; and in respect of the valuation of the Syrian investment, on which further details are included in note 6 to the Preliminary Financial Statements. The Auditor's Report did not contain statements under sections 498(2) or (3) of the Companies Act 2006.

Basis of preparation

The Preliminary Financial Statements has been prepared in accordance with the recognition and measurement criteria of International Financial Reporting Standards adopted for use in the European Union. However, this announcement does not itself contain sufficient information to comply with IFRS. The Company will publish full financial statements that comply with IFRS in early June 2015.

The Preliminary Financial Statements have been prepared under the historical cost convention except for the share-based payments and the valuation of available-for-sale investments. 

The Preliminary Financial Statements are presented in US Dollars. The majority of all costs associated with foreign operations are denominated in US Dollars and not the local currency of the operations. Therefore the presentational and functional currency of the Group, and the functional currency of all subsidiaries, is the US Dollar.

Going concern

The Preliminary Financial Statements has been prepared on the going concern basis which has been approved by the Board, notwithstanding the material uncertainty, as discussed in the going concern section of the Financial Review.

Accounting policies

The accounting policies applied in this announcement are consistent with those of the annual financial statements for the year ended 31 December 2013, as described in those annual financial statements. A number of amendments to existing standards and interpretations were applicable from 1 January 2014. The adoption of these amendments did not have a material impact on the Group's financial statements for the year ended 31 December 2014.

1. Segmental analysis of continuing operations

For management purposes, at 31 December 2014 the Group operated in three geographical areas: Morocco, Tunisia and Colombia with suspended operations in Syria as discussed in note 6. All segments are involved with the production of, and exploration for, oil and gas. The "Other" segment represents corporate and head office costs.

The Group's result and certain asset and liability information for the year are analysed by reportable segment as follows.  The comparatives for the year ended 31 December 2013 have been re-presented to remove the discontinued US operations.

Year ended 31 December 2014

	Syria	Morocco	Tunisia	Colombia	Other	Total
	$'000	$'000	$'000	$'000	$'000	$'000
Total administrative expenditure	(482)	(149)	10	(168)	(4,736)	(5,525)
Exploration costs written-off	-	(5,246)	(794)	-	-	(6,040)
Other Syrian adjustments	(202)	-	-	-	-	(202)
Operating loss	(684)	(5,395)	(784)	(168)	(4,736)	(11,767)
Financing cost						(346)
Net loss from continuing activities						(12,113)
Total assets	102,325	51,845	5,256	1,324	17,697	178,447
Total liabilities	(3,827)	(6,486)	(1,587)	(69)	(5,923)	(17,892)
E&E capital expenditure	-	19,188	794	982	-	20,964

Year ended 31 December 2013

	Syria		Morocco	Tunisia	Colombia	Other	Total
	$'000		$'000	$'000	$'000	$'000	$'000
Total administrative expenditure	(1,573)		(18)	(280)	(11)	(8,040)	(9,922)
Exploration costs written-off	-		(10,147)	(2,154)	-	-	(12,301)
Other Syrian adjustments		(383)	-	-	-	-	(383)
Inventory provision / written-off	(2,905)		-	-	-	-	(2,905)
Operating loss	(4,861)		(10,165)	(2,434)	(11)	(8,040)	(25,511)
Net financing cost credit							129
Net loss from continuing activities							(25,382)
Total assets	104,128		39,924	5,673	489	44,640	194,854
Total liabilities	(3,766)		(12,562)	(1,835)	(347)	(1,205)	(19,715)
E&E capital expenditure	474		41,783	3,553	243	-	46,053

2. Discontinued operations

In November 2014 the Group entered into a sale agreement with Hillcrest Resources Ltd to dispose of its wholly-owned US subsidiary GPUSA.   The disposal was completed on the 18 December 2014. 

The results of the discontinued operations, which have been included in the Consolidated Income Statement, were as follows:

		2014	2013
		$'000	$'000
Revenue		5,366	4,367
Expenses		(6,870)	(5,742)
Loss before tax		(1,504)	(1,375)
Attributable tax expense		-	-
		(1,504)	(1,375)
Loss on disposal of discontinued operations		(2,474)	-
		(3,978)	(1,375)
Attributable tax expense		-	-
Net loss attributable to discontinued operations (attributable to owners of the parent company)		(3,978)	(1,375)

2. Discontinued operations (continued)

During the year, GPUSA contributed $2.4 million (2013: $0.7 million) to the Group's net operating cash flows and paid $5.0 million (2013: $3.7 million) in respect of investing activities.  Cash and cash equivalents of $0.2 million were disposed of as part of the disposal of discontinued operations.

A loss of $2.5 million arose on the disposal of GPUSA being the proceeds of disposal and the carrying amount of the subsidiary's net assets, as follows:

		$'000
Property, plant and equipment		13,458
Long term financial assets		2,865
Trade and other receivables		609
Cash and cash equivalents		181
Trade and other payables		(3,601)
Provision for decommissioning		(11,031)
Net assets of discontinued operation at disposal		2,481
Consideration		50
Costs to sell		(57)
Loss on disposal of discontinued operations		(2,474)

3. Loss per share

The basic and diluted loss per share have been calculated using the loss for the year ended 31 December 2014 of $12.1 million (2013: $25.4 million) for continuing operations and $16.1 million (2013 : $26.8 million) for the loss attributable to the owners of the parent company. The basic loss per share was calculated using a weighted average number of shares in issue less treasury shares held, of 117,886,145 (2013: 117,855,702). The weighted average number of ordinary shares, allowing for the exercise of share options, for the purposes of calculating the diluted loss per share was 118,210,676 (2013: 118,192,648).

Where there is a loss, the impact of share options is anti-dilutive and hence, basic and diluted loss per share are the same.

4. Property, plant and equipment
	Oil and gas properties $'000	Other fixed assets $'000	Total $'000
Cost:
At 1 January 2013	34,799	2,397	37,196
Additions	2,467	217	2,684
Changes to decommissioning estimates	(1,859)	-	(1,859)
At 31 December 2013	35,407	2,614	38,021
Additions	2,787	401	3,188
Changes to decommissioning estimates	(92)	-	(92)
Disposals	(38,102)	(180)	(38,282)
At 31 December 2014	-	2,835	2,835
Accumulated depreciation and depletion:
At 1 January 2013	(17,351)	(1,691)	(19,042)
Charge for 2013	(1,267)	(479)	(1,746)
At 31 December 2013	(18,618)	(2,170)	(20,788)
Charge for 2014	(1,686)	(556)	(2,242)
Disposals	20,304	176	20,480
At 31 December 2014	-	(2,550)	(2,550)
Accumulated impairment:
At 1 January 2013	(4,282)	-	(4,282)
Impairment charge for 2013	(58)	-	(58)
At 31 December 2013	(4,340)	-	(4,340)
Disposals	4,340	-	4,340
At 31 December 2014	-	-	-
Net book value at 31 December 2014	-	285	285
Net book value at 31 December 2013	12,449	444	12,893

In December 2014 the Group completed the disposal of all of its US Gulf of Mexico interests, including its producing oil and gas assets, through the disposal of its wholly-owned subsidiary, GPUSA.  See note 2 for further details of this disposal.

5. Intangible assets

                                      Exploration and Evaluation assets

	Syria $'000	Morocco $'000	Tunisia $'000	Colombia $'000	Computer software $'000	Total $'000
Cost:
At 1 January 2013	10,031	--	4,796	-	2,537	17,364
Additions	474	41,783	3,553	243	421	46,474
Other write-offs	-	-	(1,000)	-	(475)	(1,475)
Exploration expenditure written-off	-	(10,147)	(2,154)	-	-	(12,301)
At 31 December 2013	10,505	31,636	5,195	243	2,483	50,062
Additions	-	19,188	794	982	10	20,974
Change in decommissioning estimates	-	977	-	-	-	977
Disposals	-	-	-	-	(123)	(123)
Exploration expenditure written-off	-	(5,246)	(794)	-	-	(6,040)
At 31 December 2014	10,505	46,555	5,195	1,225	2,370	65,850
Accumulated amortisation:
At 1 January 2013	-	-	-	-	(1,126)	(1,126)
Charge for 2013	-	-	-	-	(398)	(398)
At 31 December 2013	-	-	-	-	(1,524)	(1,524)
Charge for 2014	-	-	-	-	(46)	(46)
Disposals	-	-	-	-	52	52
At 31 December 2014	-	-	-	-	(1,518)	(1,518)
Accumulated impairment:
At 1 January 2013	(10,031)	-	-	-	-	(10,031)
Impairment provision for 2013	(474)	-	-	-	(475)	(949)
At 31 December 2013	(10,505)	-	-	-	(475)	(10,980)
Impairment provision for 2014	-	-	-	-	-	-
At 31 December 2014	(10,505)	-	-	-	(475)	(10,980)
Net book value at 31 December 2014	-	46,555	5,195	1,225	377	53,352
Net book value at 31 December 2013	-	31,636	5,195	243	484	37,558

Syria

The accumulated costs of E&E assets in Syria represent the Group's share of the drilling costs of the Al Khairat, Twaiba and Wardieh wells and certain 3D seismic surveys. The Al Khairat well was successfully tested but commercial development approval is yet to be granted by the government of the Syrian Arab Republic. The Twaiba and Wardieh wells are still under evaluation.

Following the imposition of EU sanctions against the oil industry in Syria, an impairment test was conducted and the carrying value of all E&E assets in Syria was impaired to nil as it is was  unclear whether the Group would be able to apply for commercial development approval in the manner contemplated by the Production Sharing Contract. That position remains at the date of this Report.

Morocco

Moroccan E&E assets at 31 December 2014 represent exploration expenditure on the Rharb Centre, Rharb Sud, Fes and Moulay Bouchta permits, in addition to $17.8 million of fair value attributed to the Fes, Rharb Centre and Rharb Sud permits at acquisition in 2013, less write-offs.

In respect of the Rharb petroleum contract, the  BFD-2 well was completed in early January 2014, considered non-commercial and plugged and abandoned. In 2014, $1.3 million of costs related to the three non-commercial wells in the first phase of drilling were written-off.  In addition, during 2014, $3.9 million of further abortive exploration expenditure was written-off.

In June 2014, a second phase of drilling commenced with the fourth Rharb well, LTU-1. This well discovered hydrocarbons and was temporarily suspended as a future gas producer. Drilling of the fifth well on the Rharb Centre permit, DRC-1, commenced in December 2014 and completed shortly after the year end as a discovery and also temporarily suspended as a future gas producer. At the year end, as the commerciality of these two wells had not been determined, the cost of these wells was retained in intangible assets.

Management have reviewed the carrying value of all its interests in Morocco as at the date of this Report and notes that the Rharb contract expires in November 2015 and the Fes contract in September 2015. There remain significant work obligations to be performed on both contracts as set out below and which, if not completed before expiry, could lead to ONHYM terminating those contracts.  The Moulay Bouchta contract by contrast expires in June 2016. Management have considered the risks associated with licence expiry and are optimistic that through dialogue with ONHYM and with its partner it can retain these contracts in good order. Management would seek to restructure some of the work obligations to allow the contracts to be appropriately re-financed or divested in part or whole.   Should Management be unsuccessful in this strategy, the carrying value of those assets and the restricted cash, set out below, securing those work obligations would become impaired. However, Management has considered the risks and determined that no impairment in the carrying value of its Moroccan interests is appropriate at this time.

Tunisia

At 31 December 2014, the Tunisian E&E assets represent expenditures on the Chorbane permit including amounts paid during 2013 to increase participation in the licence. During 2014, $0.8 million of abortive exploration expenditure was written-off. The Chorbane licence expires in July 2015 but Management are actively pursuing an extension to that contract following which a part or full disposal of its interests would be anticipated. Management have reviewed its intentions for these assets and the carrying value thereof as at the date of this report and concluded that no impairment of their carrying value is required. Management notes however, that if the licence is not extended or if satisfactory terms in any disposal cannot be obtained then the carrying value of this asset might become impaired. There is no security deposit or other guarantee in place with respect to these work obligations.

Colombia

The Group has interests in E&P contracts over two blocks in Colombia; LLA 50 and PUT 14, which expire in November 2016 and November 2017 respectively. At 31 December 2014 the E&E assets of $1.2 million (2013: $0.2 million) represent costs incurred in respect of these blocks which are in the early stages of exploration. Management have reviewed its intentions for these assets, which could include divestment thereof, and the carrying value of these assets as at the date of this report and concluded that no impairment of their carrying value is required.  The work obligations and the restricted cash securing these obligations are set out below. Both the asset carrying values and the restricted cash amounts could become impaired should the Group fail to satisfy the work obligations or to realise sufficient value from any divestment or farm-out.

Work obligation commitments

At 31 December 2014 the Group had the following capital commitments in respect of its exploration activities:

Morocco

Rharb permit - licence expiry date and deadline for fulfilment of capital commitments extended to November 2015

·      Drilling of a further four exploration wells.  Note DOB-1 was drilled in the first quarter of 2015.

·      Total cost of commitments outstanding estimated at $9.3 million including DOB-1.

$1 million (2013: $6 million) of deposits have been lodged to support guarantees given to ONHYM in respect of completion of these minimum work commitments. Of these amounts $1 million (2013: $1 million) is payable to a third party following release of deposits by ONHYM.  Note, by agreement subsequent to the year end, the amount repayable to the third party has reduced to a maximum of $0.5 million.

Fes permit - licence expiry date and deadline for fulfilment of capital commitments; September 2015

·      Drilling of three exploration wells.

·      Acquisition of a further 350 km of 2D seismic.

·      Acquisition of 100 km² of 3D seismic.

·      Total cost of commitments outstanding estimated at $32.8 million inclusive of a $5.7 million carry in favour of a third party.

$5 million (2013: $6.5 million) of deposits have been lodged to support guarantees given to ONHYM in respect of completion of these minimum work commitments. Of these amounts, $1.5 million (2013: $1.5 million) is payable to a third party following release of deposits by ONHYM.

Moulay Bouchta permit - licence expiry date and deadline for fulfilment of capital commitments; June 2016

·      Acquisition of a 500km of 2D seismic.

·      Reprocessing and interpretation of existing seismic data.

·      Legacy oil field reactivation survey.

·      Total cost of commitments estimated at $6.5 million.

$1.75 million (2013: $nil) of deposits have been lodged to support guarantees given to the ONHYM in respect of completion of these minimum work commitments.

Tunisia

Chorbane permit - licence expiry date and deadline for fulfilment of capital commitments; July 2015

·      Drilling of one exploration well.

·      Total commitments outstanding estimated at $7.0 million.

Colombia

Putumayo 14 - licence expiry date and deadline for fulfilment of capital commitments; November 2017

·      Drilling of one exploration well.

·      2D seismic minimum 103 km.

·      Total commitments outstanding estimated at $22.9 million.

Llanos 50 - licence expiry date and deadline for fulfilment of capital commitments; November 2016

·      Drilling of one exploration well.

·      2D seismic minimum 93 km.

·      Total commitments outstanding estimated at $14.6 million.

$3.2 million (2013: $3.2 million) of deposits have been lodged to support guarantees given to the Agencia Nacional de Hidrocarburos in respect of completion of these minimum work commitments on Putumayo 14 and Llanos 50.

The deposits referenced in this note are shown as long-term financial assets in the Consolidated Balance Sheet.

6. Investments

The Group is party to a PSC for the exploitation of hydrocarbon production in Block 26 in Syria. Pursuant to the PSC the Group operates its Syrian oil and gas production assets through a joint venture administered by DPC in which the Group has a 25% equity interest. The Group lost joint control of DPC on 1 December 2011 following the publication of European Union Council Decision 2011 / 782 / CFSP. For the purposes of EU sanctions, DPC is considered to be controlled by General Petroleum Corporation. Since the Group has neither joint control nor significant influence over the financial and operating policy decisions of the entity, it carries its investment in DPC and the associated rights under the Block 26 PSC as an available-for-sale financial asset. The fair value attributed to DPC at 31 December 2014 is $102 million (31 December 2013: $102 million).

The valuation that the Group carries for its investment in DPC is supported by the Company's economic model of the estimated future cash flows that could be generated in respect of the Group's entitlement reserves in Block 26.  The model uses oil prices quoted on the current forward Brent oil price curve, with an assumption of 2% price inflation beyond the end of the quoted curve discounted using a 15% discount rate. The basic model also assumes a short-term resumption of production. The net present value ("NPV") derived from this model ("the base case NPV") is then subjected to scenario analysis taking into account the Board's view of specific risks associated with investments in the Syrian oil and gas sector at the current time including the potential for significant delay in resumption of oil production and in receipt of revenues, potential additional costs associated with re-establishment of operations and, ultimately, a potential inability to resume operations. This methodology supports a valuation for the Group's investment in DPC of $102 million which represents a 74% discount to the base case NPV.  The valuation represents a level 3 measurement basis as defined by IFRS 7.

Note, in previous financial periods the Group used a long-term Brent oil price assumption of $90 / bbl in the valuation but, due to the recent significant fall in the oil price, the Board decided it was more appropriate to use the forward Brent oil price curve to value forecast production from the assets. Whilst this change would have a significant impact on the value of near-term production, because the valuation model scenarios include an assumption that the re-commencement of production is subject to a significant delay, the actual impact on forecast revenue values is limited.

There is a high degree of subjectivity inherent in the valuation due to the unknown duration of the sanctions and the eventual outcome of events in Syria. Accordingly it may change materially in future periods depending on a wide range of factors.

The following table sets out the impact that changes in the key variables would have on the carrying value of the asset:

	Change %	Change in carrying value of investment $'000
Increase in forecast capital expenditure	5%	(1,888)
Decrease in long-term commodity prices	5%	(6,214)
Increase in forecast operating expenditure	5%	(1,015)
Change in discount rate to 10%	5%	40,022
Change in discount rate to 20%	5%	(25,267)

The Directors have reviewed the carrying value of this available-for-sale financial asset at 31 December 2014 and are of the opinion that the valuation, although subject to significant uncertainty, remains appropriate in the circumstances, although not necessarily reflective of the value of the Group's investments in its Syrian operations over the long-term.

7. Convertible loan - Arawak Energy Bermuda Ltd

On 19 November 2014, the Group announced the closing of a convertible loan facility of $20 million with Arawak Energy Bermuda Ltd ("Arawak").  The loan has an initial available facility of $10 million with the balance of the facility available contingent upon additional exploration drilling success in Morocco. The facility has a twelve month availability period.

The loan bears interest at the rate of 10% per annum on the drawn-down facility, which is rolled up into the loan balance quarterly from the date of the draw-down.  A commitment fee of 3% is charged on the available facility undrawn during the twelve month availability period and is rolled up into the loan balance quarterly from the date of the loan draw-down. The loan matures on 30 November 2017 and is repayable in full on that date. Gulfsands may prepay the facility on 60 days notice.

The loan amount (including amounts drawn and accrued but unpaid interest and fees) is convertible at any time prior to maturity into ordinary shares of the Company, initially at a price of £0.80.  In the event that the Company issues new shares prior to conversion, repayment or maturity of the loan facility, Arawak shall have the right but not the obligation to subscribe for new shares, up to the amount of the loan amount at that time, at the same subscription price per share as paid by the other subscribers. If Arawak elects not to participate in such issue of new shares, the mechanics of conversion of the loan amount provide that an adjustment be made in order that Arawak's conversion rights will continue to represent an entitlement to the same proportion of the Company's issued share capital after the new issue of shares as they represented prior to such new issue of shares.

Gulfsands may require conversion of the outstanding balance of the loan facility into ordinary shares of the Company in the event Gulfsands' share price, on an unadjusted basis, exceeds £1.04 per share for a period of more than twenty consecutive trading days at any time prior to the expiry of the term of the facility.

 
The loan facility is secured by a share mortgage over the shares in Gulfsands Petroleum Morocco Ltd (the holding company for the Group's interests in Morocco) and a floating charge over all of the assets of Gulfsands Petroleum Holdings Limited (a subsidiary company) with further credit support provided by a guarantee from the Company.

On 25 November 2014 the Group drew-down the first $5.0 million tranche of the loan facility.

The embedded derivative element of the loan amount has been valued using a Black-Scholes model.  The model assumes an expected life of three years, a risk free rate of 0.8% and a volatility of 60%.  The valuation of the embedded derivative at the date of the first draw-down, 25 November 2014, and at the year end, 31 December 2014 is not considered material and has therefore not been separately recognised from the host loan debt instrument.  Management will continue to revalue the conversion option at subsequent accounting period ends and reassess its materiality.  The valuation represents a level 3 measurement basis as defined by IFRS 7.

The movement in the loan balance in the year is represented as follows:

	$'000
Loan draw-down	5,000
Transaction costs	(215)
Interest expense	49
Commitment fee	15
Amortisation of transaction costs	6
At 31 December 2014	4,855

Glossary of Terms

1C                              Low estimate (P90) Contingent Resources

2C                              Best estimate (P50) Contingent Resources

3C                              High estimate (P10) Contingent Resources

ADX                           ADX Energy Limited

AIM                           Alternative Investment Market of the London Stock Exchange

Arawak                     Arawak Energy Bermuda Ltd

bbl                            Barrel of oil

bcf                             Billion cubic feet of gas

boe                           Barrels of oil equivalent where the gas component is converted into an equivalent amount of oil using a  
  conversion rate of 1bcf to 0.1667 mmboe

bopd                         Barrels of oil per day

DPC                            Dijla Petroleum Company

E&E                            Exploration and evaluation

E&P                            Exploration and production

FRC                             Financial Reporting Council

G&A                           General and administrative expenses

GPC                            General Petroleum Corporation

GPUSA                       Gulfsands Petroleum USA, Inc.

Hillcrest                    Hillcrest Resources Ltd

IFRS                            International Financial Reporting Standards

km                              Kilometres

km²                             Square kilometres

KPI                              Key Performance Indicators

mboe                         Thousand barrels of oil equivalent

mcf                             Thousand cubic feet of gas

MD                             Measured depth

MENA                         Middle East and North Africa

mmbbl                      Millions of barrels of oil

mmboe                     Millions of barrels of oil equivalent

mmscfpd                   Million standard cubic feet per day

NGLs                          Natural Gas Liquids

NPV                            Net present value

ONHYM                      Office National des Hydrocarbures et des Mines (Morocco)

Possible reserves   Possible reserves are those additional reserves which analysis of geological and engineering 
   data  suggests are less likely to be recoverable than Probable reserves. The total quantities ultimately  
   recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible 
   ("3P") reserves, which is equivalent to the high estimate scenario. In this context, when probabilistic 
   methods are used, there should be more than a 10% probability that the quantities actually recovered  
   will equal or exceed the 3P estimate.

Probable reserves  Probable reserves are those unproved reserves which analysis of geological and engineering data 
   suggests are more likely than not to be recoverable. In this context, when probabilistic methods are used, 
   there should be more than a 50% probability that the quantities actually recovered will equal or exceed 
   the sum of estimated Proved plus Probable reserves.

Proved reserves      Proved reserves are those quantities of petroleum which, by analysis of geological and engineering data,  
  can be estimated with reasonable certainty (normally over 90% if measured on a probabilistic basis) to be 
  commercially recoverable, from a given date forward, from known reservoirs and under defined economic 
  conditions, operating methods, and government regulations.

P10                            There exists a 10% probability that the true quantity or value is greater than or equal to the stated P10 
  quantity or value

P50                            There exists a 50% probability that the true quantity or value is greater than or equal to the stated P50 
  quantity or value

P90                            There exists a 90% probability that the true quantity or value is greater than or equal to the stated P90 
  quantity or value

PRMS                         The 2007 Petroleum Resources Management classification system of the SPE

PSC                             Production Sharing Contract

psi                             Pounds per square inch

Senergy                     Senergy (GB) Limited

SPE                             Society of Petroleum Engineers

TD                              Total depth

WPC                           World Petroleum Congress

 

END

 

 

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