Accounts and Notice of AGM

RNS Number : 5095N

Leni Gas & Oil PLC

14 June 2010

 

 

 

 

For immediate release 14 June 2010

 

LENI GAS AND OIL PLC

("LGO" or the "Company")

 

Annual Report and Accounts and Notice of Annual General Meeting

 

Leni Gas and Oil is pleased to announce that the Company's audited Annual Report and Accounts for the year ended 31 December 2009 are being posted to Shareholders, together with a Notice of Annual General Meeting ("AGM"), and both documents and a copy of this announcement are available from the Company's website, www.lenigasandoil.co.uk . The AGM will take place on 7 July 2010 at 11.00 am at Level 5, 22 Arlington Street, London SW1A 1RD.

 

Highlights

 

OPERATIONS

·; Total production during the reporting period in Spain of 65,830 boe, with beneficial interest production in GoM of 80,560 boe, in Trinidad of 6,099 boe and in Hungary of 5,761 boe 

·; Major infrastructure expansion and modernisation of processing capacity in Spain to ensure compliance with new safety and environmental legislation, to ensure higher production reliability for new oil sales contracts and support accelerated development of the expanded reserves

·; Production step change in Spain to three times the historical production rate

·; Increase in Spain resources to 174 mmboe mean STOIIP of the existing eleven prospects

·; Identification of two new substantial oil and gas prospects in Spain with potential for a possible total Company in-country resource base of 1 billion boe

·; First development asset onstream in the GoM with processing capacity expanded to boost production

·; Increase in reserves and resources in the GoM to 1.33mmboe proved, 0.28mmboe probable, 1.96 mmboe possible, and 0.04mmboe prospective resources, with optional incremental reserves and resources of 0.33 mmboe proved, 0.65 mmboe probable, 1.65 mmboe possible and 3 mmboe of prospective resources

·; Increase in Trinidad beneficial production of 30% and decrease in opex of 50%

·; Substantial progress of the pre-drilling work programs in Malta

 

CORPORATE

·; Long term oil sales heads of agreement signed with BP to off-take the majority of Spain future production

·; Joint development agreement completed with Spain Government to research carbon capture sequestration and associated enhanced oil recovery

·; Converted the Company's shareholding in Byron Energy to a direct working interest in the Eugene Island field (three blocks) and direct exercise options in thirteen other blocks

·; Incorporated a new US subsidiary to hold all GoM interests

·; Exercised options in the GoM for two new production assets, Ship Shoal and South Marsh Island, in addition to the Eugene Island production asset

·; Incorporated and gained operator approval for a new Trinidad subsidiary to hold all Trinidad interests

·; Agreed new production licence with the Trinidad Government to expand production and exploration activities

·; Completed various framework support agreements with technical providers to provide geosciences, production engineering, operations engineering and safety environmental services to the countries of operation.

 

FINANCIALS

·; Gross profit of £1.052 million (2008: £1.091 million)

·; Pre-tax group loss of £2.053 million (2008: £0.552 million) mainly attributable to impairment charge of £1.670 million relating to write-down of Hungary investments

TARGETS

·; Expand production base in Spain with two producing assets

·; Increase processing capacity in Spain for delivering sales oil to multiple customers

·; Commence oil sales to BP and other new customers

·; Deliver on the initial stages of the revised Spain exploitation strategy for both production and exploration assets

·; Increase reserves and resources in Spain with full appraisal of the new prospects

·; Expand production base in GoM with three producing assets

·; Increase production capacity of the Eugene Island field

·; Initiate production of Ship Shoal and South Marsh Island developments

·; Exercise options in GoM for direct working interests in additional development assets

·; Commence new production licence in Trinidad

·; Expand production capacity of the Icacos field

·; Commence subsurface surveys of Trinidad prospects for future exploitation

·; Finalise pre-drilling plans for first Malta exploration and appraisal well

 

 

NOTES

·; All figures are net LGO unless otherwise stated

 

ENQUIRIES:

 

Leni Gas & Oil plc

David Lenigas, Executive Chairman/ Fraser Pritchard, Executive Director (Operations)

Tel +44 (0) 20 7016 5101

 

Beaumont Cornish Limited

Roland Cornish / Rosalind Hill Abrahams

Tel +44 (0) 20 7628 3396

 

Mirabaud Securities Limited

Rory Scott

Tel +44 (0) 20 7878 3360

 

Pelham PR

Mark Antelme / Henry Lerwill

Tel + 44 (0)20 3178 6242

 

Chairman's Statement

 

During the reporting period, the Company has made significant progress to strengthen its production base, reserves and resources and organisation across the core countries of operation in Spain, US Gulf of Mexico, Trinidad and Malta.

 

The Company's strategy to acquire and enhance existing production assets with additional exploitation potential remains unchanged and is continuing to identify opportunities to increase both the equity position of existing assets and identify additional assets in the countries of operation for greater economies of scale.

 

Since the last full reporting period the Company has step changed the performance of the Spain investment with significant achievements in all aspects of its operation including an increased production base, increased resources, improved infrastructure, and expanded organisation. These collective achievements are an essential foundation to ensure the increased potential of Spain can be fully developed.

 

During 2009 the first major well and production system rehabilitation program in 20 years was undertaken by the Company on the existing Ayoluengo production asset. This program resulted in a stabilised production rate of three times the historical production from the oilfield and an increased understanding on the potential productivity envelope of the existing production wells on Ayoluengo. This information has helped the Company to refine the exploitation tactics for the Ayoluengo asset.

 

The Company also undertook a major geotechnical review of the total Spain acreage position of almost 600km, based on the re-interpretation of the original 3D Ayoluengo seismic which was reprocessed using current processing techniques and a regional review of all geology and third party well performance.

 

The review produced numerous significant results including a greater understanding of the Ayoluengo asset geology and fault positioning which shall refine the exploitation strategy for the asset, an increase in overall resources, and significantly the identification of new prospects in the acreage, notably two substantial deeper prospects below Ayoluengo, a conventional oil reservoir and a shale gas prospect at depths between 2000m and 2700m.

 

As a consequence of the initial production increase results and expanded resources position, the Company revised the exploitation strategy for its Spain acreage and commenced major infrastructure and organisation improvements. These included a major legal compliance and capacity expansion program on the processing facilities, signature of a heads of agreement with BP for the majority of the increased production sales, signature of a development agreement with the Spanish government for a CCS enhanced recovery project and consolidation of the Company's 100% acreage position in the exploration permits through assignment of minority interests.

 

At end of the reporting period, this spectrum of achievements has clearly identified Spain as the Company's core asset with its expansion of resources and overall potential. The Company aims to reap the benefits of the 2009 achievements in 2010 and 2011 by accelerating the development of the multiple oil and gas assets using a modernised Ayoluengo processing facility as the centre of operations.

 

In the Gulf of Mexico and Gulf Coast the Company has similarly realised major achievements as per Spain with an increased production base, increased reserves and new joint venture commercial arrangements to increase our influence on our investment.

 

The major achievement of 2009 in the GoM was the undertaking of the conversion of our shareholding in Byron Energy into a direct working interest in the Eugene Island asset and direct exercise option in all properties held by Leed Petroleum and Byron Energy. This conversion was completed in January 2010 and allows the Company to become a joint venture partner in all GoM assets thereby directly influencing the investment and operations of each asset.

 

The Company now has direct or option interests in sixteen blocks in the shallow GoM shelf with exercised interests currently in the Eugene Island 172 / 183/ 184 asset, Ship Shoal 197 / 201 / 202 asset and the South Marsh Island 8 / Eugene Island 133 asset. Additional interests in two blocks are currently being evaluated by the Company, with the remaining blocks to be evaluated during 2010 and 2011.

 

The Eugene Island field is the first asset on production and the development drilling was completed in early 2009 at an initial production rate of 6000 boepd of which the Company now has a 7.25% working interest. During 2009 production from the field averaged 3000 boepd for the year due to a variety of third party and field improvements and interventions. Notable of these were increases in gas transportation ullage, installation of compression to boost production from the legacy field wells, and multiple re-completions to develop the multiple pay zones. The largest of the pay zones has yet to be developed and the Company expects this zone will maintain the 2009 average production rate into 2012.

 

At end of reporting period the Company evaluated and exercised its option to participate in the Ship Shoal 197 / 201 / 202 and South Marsh Island 8 / Eugene Island 133 assets. The first well in the Ship Shoal asset was successfully completed and tested in March 2010 and has recently commenced production. The Company expects the South Marsh / Eugene Island asset to commence development in late 2010.

 

In Trinidad the Company has made considerable technical, legal and commercial progress during 2009 to strengthen the foundation of the Trinidad investment and ensure a simplified operating structure is in place for the 2010 development plans.

 

The most notable progress has been the negotiations with the Trinidad Ministry of Energy to agree a new 20 year production licence for the existing production asset, which is due to commence imminently, and the creation and operator approval of a new subsidiary to hold all Trinidad investments to execute on the licence commitments. The Company is also in discussions with the Trinidad Government to increase the Company's interests through acquisition of other licences.

 

 

The Company has also increased its organisational capability in-country and through direct intervention has increased beneficial production by 30% and reduced opex by 50%. The new licence commitments have the potential to expand these targets considerably with full rehabilitation of the current production system, modern geotechnical interpretation of the total acreage and drilling of both infill targets and deeper prospects.

 

Malta is the Company's only non-producing asset though has company-maker potential with a billion barrel resources base. During the reporting period, the Company and the joint venture operator progressed the pre-drilling work program to improve the understanding of the highest potential drilling prospects ahead of the July 2011 drilling target. This work program continues to maximise the chance of success of the first Malta drilling target.

 

During the period the Company de-risked the portfolio by relinquishing its interests in Hungary and Switzerland. Hungary was a dual company investment including a multiple prospect gas redevelopment project and a joint venture with MOL for regional asset redevelopment.

 

The economics of the gas redevelopment project deteriorated during 2009 with increasing capital costs, unsuccessful drilling programs and decreasing production revenues. The MOL joint venture failed to propose an economic development program for a gas redevelopment project and presented high exploration risk for another project.

 

After conducting a comprehensive economic review of the Hungary investment with the Company's technical providers under all potential pricing scenarios, it was concluded neither venture would provide a material return on the Company's investment. Although various third parties expressed an interest in acquisition, none were successful, so the Company relinquished its interests and reallocated the capital savings to corporate capital funding.

 

Over the next reporting period, the Company is planning to accelerate development plans in all countries, to have multiple producing assets in both Spain and the Gulf of Mexico, to progress appraisal of the deeper prospectivity and exploration prospects in Spain, to step change production operations in Trinidad, and to have sufficiently progressed the pre-drilling plans in Malta to commence well planning.

 

At the end of the current reporting period the Company reported annual production of 65,830 boe in Spain and 5,761 boe in Hungary, with beneficial interest production of 80,560 boe in GoM and 6,099 boe in Trindiad.. This figure was below the Company's 2009 target though this was as consequence of expanded well interventions to maximise long term well productivity.

 

Significant non-production targets were achieved including a substantial increase in reserves and resources, an expanded and lower risk exploitation strategy for Spain and a transformed commercial structure in Trinidad to accelerate development.

 

The Directors are delighted with the performance during the reporting period as it strengthens our position in all countries, reinforces the value and potential of our investments, bolsters our commercial foundation in all countries and reduces the risk on our future exploitation plans.

 

Although the market conditions remain challenging and investment financing in the oil and gas sector remains in a tenuous state, the Directors are excited about the future with a robust foundation in all countries set to deliver step change production revenue.

 

We would like to take this opportunity to thank all of our staff and contractors for their tremendous effort during 2009 and our shareholders for their ongoing support.

 

 

 

 

 

 

David Lenigas

Executive Chairman

Operations Review

 

Leni Gas and Oil plc has a strategy to identify and acquire projects and businesses within the oil and gas sector that contain a development premium which can be unlocked through a combination of financial, commercial, and technical expertise.

 

The Company operates a low risk portfolio of production expansion assets in the US Gulf of Mexico, Spain, Trinidad and Malta with significant play upside using similar operating approaches to leverage technologies and proven production enhancement techniques. LGO specifically targets near term production with upside exploitation potential and manages its portfolio to ensure all assets have accelerated incremental reserves and production enhancement programs.

 

A summary of period activity in all countries of operation during the reporting period follows:

 

 

SPAIN:

 

LGO retains 100% ownership through its wholly owned subsidiary, Compañia Petrolifera de Sedano, in one production concession, La Lora (which contains the Ayoluengo producing oilfield), and three exploration permits, Basconcillos H, Huermeces and Valderredible, in north Spain. These interests were acquired in November 2007, with interests in the exploration permits increased from 85% to 100% in December 2009.

 

The permits are centrally located in the proven Basque-Cantabrian petroleum basin and span an area of over 550 sqkm, with a processing facility designed to handle 10,000 bbls per day and store 21,000 bbls centred on the producing Ayoluengo oilfield which itself spans an area of 14 sqkm.

 

The 2009 work program included various phases of well rehabilitation and stimulation on the Ayoluengo oilfield and various feasibility and appraisal activities in the exploration permits.

 

The approved Ayoluengo 2009 work program in January 2009 targeted efficiency improvements to the production facilities, optimisation of the well pumping systems, and rehabilitation and cleanout of the producing wells to improve productivity of the existing perforated zones.

 

This work program had never been conducted in the previous 20 years of the field operation and therefore a long campaign was required to complete the scope. As a consequence of the extended rehabilitation program during 2009, a large percentage of production from Ayoluengo was shut-in during 2009.

 

The results of this initial stimulation program realised a stabilised production of 300 bopd, with peak production considerably higher at 440 bopd. The stabilised rate is three times the historical production from the oilfield. The substantial increase in oil production, after almost 20 years of static production of 100 bopd, and a major increase in gas production confirmed both the re-pressurisation of existing zones and the presence of un-depleted production zones.

 

The stimulation program also provided invaluable information on the maximum potential of the existing wells and their production system as the program re-opened all four producing reservoir zones in each well resulting in major increases of differential oil, gas and water production.

 

In August 2009 the Company announced new oil sales agreements were being negotiated to identify multiple off-take customers to increase both the monthly volume sales and commodity price with additional treatment facilities under design to re-grade the oil for refinery feedstock. Subsequent to these discussions the Company announced the completion of a Heads of Agreement with BP España ("BP") in May 2010 to negotiate a crude oil sales agreement to off-take the Company's current and future Spain production to BP's Castellón refinery in eastern Spain.

 

During Q4 2009, the 3D seismic shot over Ayoluengo by Chevron in the early 1990s was reprocessed using modern techniques, and during Q1 and early Q2 2010, was re-interpreted by Equipoise Solutions Ltd ("Equipoise") to improve the Company's understanding of the oilfield, de-risk production development programs and assess the deeper prospectivity which was reported in May 2010.

 

Reprocessing the Ayoluengo 3D seismic data resulted in a clearer structural image of the field, a more accurate determination of the fault positions and revised deterministic and probabilistic estimates of STOIIP for the producing Lower Cretaceous and Upper Jurassic reservoirs. The overall STOIIP increased to 105.72 mmbo Mean, 117.56 mmbo P10, 105.41 mmbo P50 and 94.19 mmbo P90. Historical cumulative production is 17.16 mmbo and 16.14 bcf (19.85 boe) equivalent to an 18.8% recovery factor.

 

Oil in place for the Lower Cretaceous and Upper Jurassic reservoirs was redistributed between the main east and west flanks of the reservoirs (east reduced to 79.5 mmbo from 83.6 mmbo, and west increased to 27.3 mmbo from 20.6 mmbo), with historical recovery factors of 21% east and 5% west.

The new interpretation, remapping of primary and secondary faults and identification of increased resources in the west flank, has revised and de-risked the Company's future production expansion plans for Ayoluengo. The previous development strategy of maximising the productivity of the existing aging wells and conducting selected infill drilling has been determined to be sub-optimal and therefore will not maximise production.

 

The Company has redefined the Ayoluengo development strategy based on the improved understanding of the reservoir to ensure the majority of the fifty three wells can contribute to maximising production. A two-tiered strategy on the existing producers and also the current shut-in wells will be adopted.

 

The existing producers will undergo a near term plan to perforate the undepleted zones, shutoff water and gas to maximise oil production and install subsurface pumping systems to improve reliability. The shut-in wells will be selectively re-opened and artificial stimulation methods using nitrogen, carbon dioxide and polymer barriers shall be used to mobilise the oil. In parallel selective wells will undergo a batch horizontal sidetrack program using radial jetting, which is less expensive than drilling, to access discontinuous undepleted zones and increase the depletion radius of all wells.

 

The revised geotechnical assessment reported in May 2010 also identified two new prospective hydrocarbon carbonate intervals in the Lower Jurassic underneath the Ayoluengo Lower Cretaceous and Upper Jurassic producing zones. A conventional hydrocarbon reservoir was identified between 2000m and 2300m subsurface and an unconventional gas prospect at depths down to 2700m subsurface.

 

The conventional reservoir was estimated to have a nominal gross reservoir sequence of 80m with a large gross rock volume of 780 million m3 (equivalent to a 10 sqkm footprint) to the reservoir structure boundary. A high probability of reservoir quality formations has been identified due to a locally high structure centred on Ayoluengo, hydrocarbon flows to surface from the Hontomin 2 and Ayo 1 wells, traces of oil stain within the cores and a good porosity range of 10-17% from the core evaluation.

 

The unconventional reservoir was assessed as immature for oil production, but is likely to be locally mature for shale gas production based on the regional geological review and Ayoluengo re-interpretation. The size of the shale gas generation window below Ayoluengo is considerable and similar structures in North America can have substantial GIIP density. Should the Ayoluengo Lower Jurassic shale prospect be comparable to North American structures, the prospect would equate to a deterministic GIIP of 3.8 tcf (630 mmboe).

 

Due to the age of the available data (1960s) and absence of quantitative data at depth, modelling of both reservoirs has been difficult due to distribution of reservoir parameters, and thus a conservative prognosis has been assumed at present. Work is therefore ongoing to improve the accuracy of the reservoir potential through a comprehensive local and regional appraisal program.

 

The approved 2009 program for the exploration permits reported in January 2009 included the design of an extended well test in the Huermeces Hontomin discovery, assessment of development options in the Basconcillos H Tozo discovery, and definition of the exploration activities required for the remaining identified prospects throughout the acreage.

 

In March 2009 the Company announced completion of a joint development agreement with the Ciudad de la Energia (CIUDEN) for the research, testing and implementation of carbon dioxide (CO2) sequestration pilot sites in Spain. CIUDEN is a Spanish foundation incorporated by the Ministry of Industry, Trade and Tourism, the Ministry of the Environment and the Ministry of Science and Innovation within the Spanish Government.

 

Under terms of the joint development agreement, CIUDEN with the support of LGO shall identify and carry out work programs to research, test and implement activities to evaluate CO2 sequestration on two assets within LGO's Spain acreage. All work programs are wholly funded by CIUDEN and will be performed on the Hontomin and western flank of Ayoluengo to assess CO2 injection, storage and enhanced oil recovery.

 

The 2010 work program with CIUDEN, the Spanish Government Foundation for carbon capture and storage, was agreed in December 2009 with works approved for Hontomin and West Ayoluengo injection testing.

 

In April 2009 the Company confirmed that all regulatory permits and approvals have been issued to commence the planned extended well test on the Hontomin-2 well within the Huermeces exploration permit. The objective of the extended well test is to appraise the long term production potential of the well and determine the optimum exploitation plan for the Hontomin field which has a mean STOIIP of 2.40 mmbo. The Hontomin 2 well initially tested at an initial rate of 700 bopd and was shut-in at a rate of 50bopd.

 

The well test will assess the commerciality of the well and the reservoir properties of the Lower Jurassic interval to assist with development of the larger conventional oil prospect underneath Ayoluengo. During the well test CIUDEN will conduct a 3D seismic survey and monitoring activities to assess the CO2 sequestration potential. The results of the well test and CIUDEN activities shall define the overall exploitation strategy for Hontomin which has the potential to exceed reserves recovery above 50% from the Hontomin structure.

 

All production from Hontomin will be transported 38km to the production facilities at the Ayoluengo oilfield for processing and oil sales. The site preparation works for the extended well test are complete and the extended well test will commence upon completion of upgrades to the processing facilities and drilling facilities at Ayoluengo.

 

In June 2009 a feasibility study was completed on the Basconcillos H Tozo discovery to develop the gasfield with a gas to power scheme identified as the most economical way to develop the prospect due to its size and location. The Tozo discovery has mean contingent gas reserves of 2.9 bcf. The Company issued a permit application in July 2009 for this scheme to be developed with Spain's regional Government, national electricity provider and local industrial and residential consumers. Consequently in May 2010 the Company submitted an application for a three year extension to the Basconcillos H exploration permit.

 

Assignment of the minority interests, 15%, in the exploration acreage from Tethys Oil Spain AB to the Company was completed in December 2009. The Company's Spain subsidiary now retains 100% of the exploration acreage, in addition to 100% of the production concession acreage.

 

During the regional geology review reported in May 2010, additional potential prospects were identified within the Basconcillos H and Valderredible exploration permits and these are currently being evaluated.

 

 

 

In order to provide the foundation for the production expansion of both Ayoluengo and the surrounding prospects, the Company engaged SGS at the end of 2009 who is the world's leading inspection, verification, testing and certification company and is recognised as the global benchmark for quality and integrity. The Ayoluengo processing facility required a major survey and compliance program at the end of 2010 to meet new European safety and environmental legislation, and modernisation of the facilities was also required to support higher volumes, artificial stimulation and multiple sales customers. These works shall continue throughout 2010.

 

The revised development strategy for the acreage has required a step change in how the various programs are executed and the Company has evolved its supply chain as announced in May 2010 from local vendors to large international oilfield service providers. Contract negotiations are currently being finalised with these providers to ensure the diversity of programs required to maximise field recovery at Ayoluengo and the other prospects can be successfully executed.

 

The Company reported in May 2010 the total STOIIP of the currently assessed prospects across the acreage which can be developed is 173.8 mmbo Mean, 265.2 mmbo P10, 151.4 mmbo P50, and 108.3 mmbo P90. This STOIIP excludes the deeper prospects sub 2000m below Ayoluengo and the additional potential prospects identified within the Basconcillos H and Valderredible exploration permits.

 

Total net production during the reporting period (from the Ayoluengo oilfield within the production concession) was 63,461 bbls of oil and 14.212 mmscf of gas, equivalent to 65,830 boe.

 

 

US GULF OF MEXICO:

 

LGO retains rights within sixteen blocks in the GoM from its investment in Byron Energy LLC ("Byron") in 2008. As announced in April 2009 and completed in January 2010 an agreement was executed to convert the Byron investment into direct working interests and exercise options in the GoM acreage. The sixteen blocks in the GoM encompass interests in leases West Cameron, South Marsh Island, Eugene Island, Ship Shoal, Grand Isle and Main Pass. The Company currently retains direct working interests in Eugene Island and Ship Shoal leases with exercise options in the remainder.

 

The Eugene Island Field is located 50 miles offshore Louisiana in approximately 80 feet of water, and is operated by Leed Petroleum plc ("LDP") on behalf of the joint venture with Byron and LGO. Production in the field comes from the Tex X2, Tex X3, T-1 and Mid Tex sands at depths ranging from 12,000 to 15,000 feet.

 

The Eugene Island asset is the first of the interests to be developed and during the reporting period the first stage of three development wells was successfully completed. At start 2009 the A-7 had been successfully tested at 4,012 boepd gross in the Mid Tex pay zone, which is one of six pay zones identified in a column of 181ft net pay. In January 2009, the A-8 well was completed and successfully tested at 2,557 boepd gross in a 96ft pay zone. After A-8 was placed on production, in February 2009, the A-6 was successfully re-completed and tested at 1,750 boepd gross.

 

At commencement of full production, the Eugene Island production platform was delivering 6,000 boepd gross, at 2,500 bbls of oil and 21 mmscfd of gas. During 2009 production from Eugene Island declined from this initial figure due to natural depletion and the onset of water production from some of the wells.

 

The 2009 work program for Eugene Island included the maintenance of the main third party gas pipeline for sales gas transportation, installation of a new low pressure compressor to boost the production from the original Eugene Island wells, and various re-completions and interventions on the A6, A7 and A8 wells to develop behind pipe reserves and shutoff watered out zones.

 

This work program although impacting the production availability during the year maintained an average production during the reporting period of half the initial production rate at 3000 boepd. Considerable behind pipe reserves remain to maintain this production level into 2012, with the joint venture strategy to deplete each pay zone in series prior to bringing onstream the main reserves within the T1 reservoir sands.

 

In April 2009 LGO announced the completion of a Heads of Agreement with Byron Energy to transfer the Company's shareholding in Byron Energy from an indirect to a direct ownership of its GoM oil and gas assets and an opportunity for portfolio expansion.

 

Under terms of the agreement LGO converted its 28.94% interest in Byron Energy to a 7.25% direct working interest in Eugene Island Blocks 183 and 184 south and a 3.625% direct working interest in Blocks 172 and 184 north (collectively referred to as "Eugene Island Field").

 

The agreement also included the option to acquire 29% of Byron Energy's interest in all option properties in the GoM under the existing Leed Petroleum Plc / Byron Scouting Agreement. In addition LGO will also have the option to acquire up to a 20% direct working interest in properties acquired independently by Byron Energy with effect from December 2008 by paying 30% of all costs.

 

In April 2009 the Company announced the acquisition by Leed Petroleum of the Ship Shoal Block 202 lease from Mariner Energy, Inc. for a gross consideration of US$150,000. The lease is adjacent to the Ship Shoal 201 Block, which Leed already owns and operates, and includes the Ship Shoal 202 "A" platform which shall be used to access the development targets on Ship Shoal Blocks 197, 201 and 202. As consideration for the acquisition of the platform, Leed will assume the estimated abandonment liability of no more than $2 million. At end 2009, Byron and the Company exercised their option to acquire 25% of Block 202, of which LGO has 7.25%.

 

 

 

In May 2009, Leed Petroleum announced the award of the Eugene Island 133 and Ship Shoal 197 leases in the Gulf of Mexico under the Minerals Management Services ("MMS") Lease Sale 208. The Eugene Island 133 block is adjacent to existing South Marsh Island block 8 option and the Ship Shoal 197 block adjacent to block 201 and 202. The leases will each be held for an initial five year "primary" term during which Leed will have the right to explore and produce hydrocarbons.

 

In July 2009, the exercise options on Ship Shoal block 205 and South Marsh Island blocks 5 and 6 expired as the joint venture considered neither block had any attributable resources.

 

During Q4 2009, in relation to the conversion agreement to transfer the Company's shareholding in Byron Energy to direct ownership, completion agreements were signed by both parties, Byron Energy shareholders approved the transaction and LGO's US subsidiary was properly authorized by the relevant authorities in the US to hold these interests. Full completion of the conversion agreement was announced in January 2010 after the full transfer of rights by Byron Energy's Australia parent company to the LGO US subsidiary.

 

As of the conversion completion the Company now holds interests and options in sixteen properties within the GoM acreage. LGO retains a 7.25% direct working interest in Eugene Island blocks 183 and 184 south, a 3.625% direct working interest in block 184 north and a 3.00649% direct working interest in block 172. Net revenue interests range from 2.50540% to 6.04167%.

 

The Ship Shoal development encompasses blocks 197, 201 and 202 and is located 125 miles offshore Louisiana in approximately 100 feet of water. The Company exercised in February 2010 its rights on the Ship Shoal development, with completed interests in block 197 (direct working interest 7.25%, net revenue interest 5.7819%) and block 202 (direct working interest 7.25%, net revenue interest 6.0417%) with an overriding royalty in block 201 (0.4714%).

 

The Company also exercised its rights in February 2010 on the South Marsh Island development (block Eugene Island 133). The remaining block on the development, South Marsh Island block 8, remains to be exercised and is scheduled for September 2010 after further geological interpretation.

 

The Company retains exercise options on South Marsh Island block 8, Grand Isle blocks 95 and 100, Main Pass block 115 and West Cameron block 106. These options shall be notified for exercising once Leed Petroleum issues the development plan and budget in late 2010 and 2011. Under terms of the LDP Byron Scouting Agreement, the Company retains an exercise option to acquire 29% of Byron's interests in these developments, equivalent to a direct 7.25% direct working interest, with net revenue interests between 5.8906% and 6.0417%.

 

In March 2010 the first Ship Shoal development well was successful drilled and evaluated at a restricted rate of 2,153 boepd (20% oil, 80% gas) after encountering 65 feet of true vertical thickness pay. Commencement of production is expected to occur during Q2 2010.

 

The South Marsh Island development encompasses South Marsh Island block 8 and Eugene Island block 133. The development is located 90 miles offshore Louisiana in approximately 60 feet of water, was initially developed by Chevron and produced from numerous sands from 10,000 to 15,000 feet.

 

The Company also retains exercise options in South Marsh Island block 6 and Ship Shoal block 180 which were awarded to Byron independently in April 2010 and are covered within the Company's Strategic Scouting Agreement with Byron to acquire up to a 20% direct working interest in these blocks. The Company has notified Byron of its intention to exercise these options and is currently completing the assignment agreements.

 

LGO net reserves across all existing exercised GoM interests are 1.33mmboe proved, 0.28mmboe probable, 1.96 mmboe possible, and 0.04mmboe prospective resources, in accordance with the competent person's report of March 2009.

 

Unaudited potential incremental reserves and resources assuming all current exercise options are completed are 0.33 mmboe proved, 0.65 mmboe probable, 1.65 mmboe possible and 3 mmboe of prospective resources.

 

Total net production during 2009 (from the Eugene Island production asset) was 29,552 bbls of oil and 306.049 mmscf of gas, equivalent to 80,560 boe.

 

 

TRINIDAD:

 

The Company retains 50% rights to the Icacos oilfield, covering 1,900 acres, located on the Cedros Peninsula of Southern Trinidad, within the East Venezuelan Basin.

 

During 2009 an increase in production of 30% was achieved by selected workovers on the existing production wells and improving the infrastructure. Lifting costs were also reduced by almost 50% by optimising the resourcing.

 

In July 2009 the Company agreed with the Trinidad Ministry of Energy to negotiate and finalise a new production licence for the Icacos oilfield to accelerate exploitation. During the second half of 2009, this new production licence was negotiated to agree a term of 20 years and include a three year work program to rehabilitate current production zones, conduct geological surveys and interpretation to identify new and undepleted zones for step out production drilling, and undertake an appraisal of the deeper prospectivity.

 

 

In September 2009 the Company submitted acquisition proposals to the joint venture partner to acquire their interests and assume whole ownership of the Oilfield. This proposal continues in negotiation due to the ongoing divestment by the parent company of the joint venture partner to relinquish its interests in all Trinidad operations.

 

The Company also submitted an unsuccessful bid to the state oil company, Petrotrin, during 2009 to acquire additional onshore production assets in Trinidad.

 

The Company incorporated Leni Trinidad Limited in November 2009, which is wholly owned by LGO, to simplify the commercial arrangements of its activities in Trinidad. It has recently assigned all Trinidad interests to Leni Trinidad Ltd. The production licence discussions with the Ministry of Energy during 2009 also included the proposal for Company to assume operator control of the Icacos oilfield. Consequently Leni Trinidad Ltd has been qualified as an operator in Trinidad and shall assume operator control of Icacos on licence commencement.

 

The Company is currently in discussion with PricewaterhouseCoopers Trinidad regarding the acquisition of the joint venture partner's interests, and is awaiting Minister of Energy signature to the new production licence to commence execution of the new licence commitments on the Icacos oilfield.

 

Total net beneficial production from the Icacos oilfield during the reporting period was 6,099 bbls of oil.

 

 

MALTA:

 

LGO retains 10% in Area 4 Blocks 4, 5, 6 and 7 of Southern Offshore Malta with Mediterranean Oil & Gas ("MOG") retaining the balance. The Area is governed by a Production Sharing Contract with the Maltese Ministry of Natural Resources with a commitment to drill by July 2011.

 

Four prospects and five leads on the 5,700 square km PSC Area have been delineated, with the total most likely hydrocarbon potential of the PSC Area estimated at gross 5 billion barrels of oil in place with resultant total most likely case prospective recoverable oil resources of 1.475 mmbo gross. 

 

The approved 2009 work program was to increase the understanding of the prospect and leads and increase their relative chance of success for identifying the highest potential for drilling in 2010 and 2011, through various activities including the feasibility and acquisition of electromagnetic and gravity data, depth re-processing on the acquired 3D seismic and acquisition and interpretation of non-seismic data. The 2009 Work Program had a gross budget cost of 2.5 million USD with LGO contributing 250,000 USD.

 

An Advisory Committee Meeting was held between LGO, MOG and the Maltese Ministry in July 2009 to discuss the work program progress for drilling preparations. The PSC partners are continuing on the work program including various geosciences studies and surveys to complete the technical assessment of the area and finalise the best strategy for the drilling.

 

 

HUNGARY:

 

In July 2008, the Company completed an agreement with Ascent Resources plc to acquire a 7.27% interest in PetroHungaria kft and a 14.54% interest in ZalaGasCo kft in East and West Hungary respectively. PetroHungaria kft ("PetroHungaria") owns a 100% interest in the Penészlek gas development project in the Nyirség exploration permits in eastern Hungary and ZalaGasCo kft has a joint development agreement with MOL Hungarian Oil & Gas for a 50% interest in gasfield redevelopment projects in Hungary.

 

In March 2009 a new seismic interpretation of the Penészlek Development area was completed with a revised development strategy to target the identified resources via five possible drilling locations. Gross unrisked mean GIIP from the drilling locations totalled 14.65 bcf, with contingent gas resources of 4.87 bcf and prospective gas resources of 4.65 bcf.

 

A work program to develop all five locations in 2009 was provisionally approved by the joint venture partners in March 2009. The Pen-104a sidetrack completed in April 2009 to target recoverable resources of 0.6 bcf gross and achieved a stabilised production of 3 mmscfd gross. The Pen-105 development well was completed and tested in August 2009 to target mean contingent gas resources of 1.46 bcf in two Miocene reservoirs. The Joint Venture completed a further sidetrack of the Pen-104 well ('Pen-104AA') to test a Miocene volcaniclastic prospect at end 2009.

 

Total net beneficial production from the Penészlek gas development project during the reporting period was 34.623 mmscf of gas and 2 bbls of condensate, equivalent to 5,761 boe.

 

ZalaGasCo kft retains a 50:50 joint venture with MOL for the re-development of gas projects in Hungary. A pilot project on the producing Bajcsa gasfield was scoped at start 2009 with a horizontal drilling well into proven productive gas reservoirs to determine reservoir response though this was deemed uneconomic by the Company.

 

The Company entered into a dispute with Ascent Resources plc in July 2009 concerning the exclusion of LGO from a new project with MOL under the terms of the ZalaGasCo Kft joint development agreement. In October 2009 the Company resolved the dispute with terms agreed whereby LGO had the option to become a 14.54% shareholder in the new project.   The Company conducted a commercial review of its interests in Hungary at end 2009 due to the increasing capital costs, decreasing revenue and minimal forecast net earnings in PetroHungaria, the failure to achieve substantive progress in ZalaGasCo, the high exploration risk associated with the new MOL project and the failure to maximise the Company's investment in Hungary by the operator.

 

The commercial review was conducted with the Company's geotechnical provider, Equipoise Solutions Ltd ("Equipoise"), and production technology provider, Eclipse Petroleum Technology Ltd ("Eclipse"), and concluded both ZalaGasCo and PetroHungaria ventures would not provide a material return on the Company's investment of 2 million Euros for Hungary.

  Discussions were conducted with third parties to divest the Company's whole interests in Hungary though these were not successful. Consequently in March 2010 Company decided to relinquish its acreage in both ZalaGasCo and PetroHungaria, write off the Hungary investment in the Company accounts and reallocated future Hungary development capital to the other countries of operations.

 

 

SWITZERLAND:

 

The investment in the Hungary assets resulted as a variation in the option to acquire a 10% interest in Ascent Resources plc Seeland Freinisburg Exploration Permit in Switzerland, which was executed in order to de-risk the Company's portfolio from high risk exploration to mature production upside assets. The Company's option with Ascent to farm into the Switzerland gas acreage on the original terms until April 2010 was withdrawn by Ascent in January 2009.

 

 

OTHER:

 

The Company completed various framework agreements with technical providers during the reporting period to provide geosciences, production engineering, operations engineering and safety environmental services to the countries of operation.

 

These companies include Interactive Exploration Solutions, Inc. (US), Advance Petroleum Services Ltd (Trinidad), Equipoise Solutions Ltd (UK), Eclipse Petroleum Technology Ltd (UK) and SGS SA (Spain).

 

 

Competent Person's statement:

The information contained in this announcement has been reviewed and approved by Fraser S Pritchard, Executive Director for Leni Gas & Oil Plc (member of the SPE) who has over 20 years relevant experience in the oil industry.

 

 

 

Finance Review

 

Economic environment

The performance of the Company will be influenced by global economic conditions, and in particular, the conditions prevailing in the United Kingdom, Spain, USA and Trinidad. The economies in these regions have all been subject to recessionary pressures during the period, with the global economy experiencing continued difficulties during 2009 and into 2010. Although the financial markets have settled a little from the turmoil of late 2008 and early 2009, liquidity in the banking and investment sectors remains tighter than prior to 2008. The Company continues to monitor all of these markets particularly in relation to the Company's future project and operational development plans.

 

Results for the period

2009 continued to mark a real turning point in the evolution of Leni Gas and Oil plc. Encouraging production increases arose from developing our Spanish, US and Trinidad operations. The financial statements presented herein do not as yet represent this real shift in direction but the immediate years ahead should reflect this.

 

LGO is primarily a development business with programs in place to monetise the Company's interests in various oil and gas operations. Expectations are forecast of a significant increase in production volumes and therefore revenue in the next few years. The results for the year reflect this status and the Group recorded a gross profit of £1.05 million (2008: £1.09 million) and an operating loss after tax of £2.06 million (2008: £0.55 million) for the period ended 31 December 2009 mainly attributable to an impairment charge of £1.67 million relating to the write-down of the Company's investments in Hungary and £0.17 million for non-cash share based payments.

 

Turnover in the period of £2.13 million (2008: £2.13 million) arose from Spanish oil and gas sales.

 

Cash flow

Cash flow from operating activities before movements in working capital amounted to £0.15 million (2008: £0.24 million). After working capital items, net cash outflow from operating activities was £1.18 million (2008: £0.39 million). Net cash inflow from financing activities was £0.45 million (2008: £13.26 million). Net cash outflow from investing activities was £1.80 million (2008: £18.34 million) which £1.86 million (2008: £14.54 million) was incurred on capital expenditure relating to field development and exploration in all countries of operation.

 

Net cash position

Net cash at 31 December 2009 was £0.23 million. (2008: £0.57 million).

Since year end, net cash has been increasing due to operational cash flows.

 

Key performance indicators

The current business of the Company is fundamentally in a development and initial production stage with the focus on the successful delivery of investment to enable the Company to progress to substantial oil and gas sales and a larger operational business. The Company has devised strategies to monetise the majority of its oil and gas assets primarily by means of various production enhancement, development expansion and commercial consolidation programs as outlined in the Operations Review. The Board and management are incentivised to deliver shareholder value in line with these plans. The Company intends to provide detailed analysis and comparison of production; cash flows from operations; operating costs per boe; and realised oil and gas prices per barrel and mscf in future Annual reports.

 

Outlook

Having acquired various oil and gas assets and securing the team to expedite the various implementation plans, LGO's financial future is very promising. With the prospect of generating significantly increased operational cashflow in the foreseeable future, the real monetisation of our assets and delivery of their potential is commencing.

 

Competent Person's statement: 

The technical information contained in this announcement has been reviewed and approved by Fraser S Pritchard, Executive Director (Operations) for Leni Gas & Oil Plc (member of the SPE) who has 20 years relevant experience in the oil industry.

 

GLOSSARY & NOTES

 

bcf = billion cubic feet

boe = barrels of oil equivalent calculated on the basis of six thousand cubic feet of gas equals one barrel of oil

boepd = boe per day

bbls = barrels of oil

bopd = barrels of oil per day

bwpd = barrels of water per day

Byron Energy = Byron Energy Pty Ltd

CCS = carbon capture and sequestration

Contingent Resources = those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from known accumulations but which are not currently considered to be commercially recoverable.

CO2 = carbon dioxide

EOR = enhanced oil recovery

GIIP = Gas Initially In Place

GoM = US Gulf of Mexico and Gulf Coast

LDP = Leed Petroleum plc

Leed = Leed Petroleum plc

LGO = Leni Gas & Oil plc

m = thousand

mm = million

mmscf = million standard cubic feet of gas per day

mmscfd = mmscf per day

MOL = MOL Hungarian Oil & Gas

MOG = Mediterranean Oil & Gas plc

Prospective Resources = those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from undiscovered accumulations.

Proved Reserves = the estimated volumes of crude oil, condensate, natural gas and natural gas liquids which, based upon geologic and engineering data, are reasonably certain to be commercially recovered from known reservoirs under existing economic and political/regulatory conditions and using conventional or existing equipment and operating methods

STOIIP = Stock Tank Oil Initially In Place

 

All figures are net LGO unless otherwise stated

All reserves and resources definitions used are per the Society of Petroleum Engineers' Petroleum Resources Management System.

 

 

Financial Statements

GROUP STATEMENT OF COMPREHENSIVE INCOME FOR THE YEAR ENDED 31 DECEMBER 2009

 

		Year ended 31 December 2009	Period 01 September 2007 to 31 December 2008
	Notes	£ 000's	£ 000's
Revenue	2	2,133	2,131
Cost of sales		(1,081)	(1,040)
Gross profit		1,052	1,091
Administrative expenses	3	(988)	(993)
Share based payments	20	(169)	(675)
Loss from operations		(105)	(577)
Impairment charge	12	(1,670)	-
Share of associate's results	13	(344)	(128)
Finance revenue	9	66	153
Loss before taxation		(2,053)	(552)
Income tax expense	5	(6)	-
Loss for the year		(2,059)	(552)
Other comprehensive income
Exchange differences on translation of foreign operations		(151)	494
Other comprehensive income for the year net of taxation		(151)	494
Total comprehensive income for the year attributable to equity holders of the parent		(2,210)	(58)
Loss per share (pence)
Basic	8	(0.34)	(0.12)
Diluted	8	(0.34)	(0.12)
All of the operations are considered to be continuing.

GROUP STATEMENT OF FINANCIAL POSITION AS AT 31 DECEMBER 2009

 

		As at 31 December 2009	As at 31 December 2008
	Note	£ 000's	£ 000's
Assets
Non-current assets
Property, plant and equipment	11	386	480
Intangible assets	10	7,689	7,533
Interest in associate	13	14,072	14,416
Total non-current assets		22,147	22,429
Current assets
Inventories	16	168	129
Trade and other receivables	15	922	1,129
Cash and cash equivalents		230	571
Total current assets		1,320	1,829
Total assets		23,467	24,258
Liabilities
Current liabilities
Trade and other payables	17	(1,358)	(494)
Borrowings	18	(453)	-
Total current liabilities		(1,811)	(494)
Non-current liabilities
Provisions	19	(858)	(925)
Total non-current liabilities		(858)	(925)
Total liabilities		(2,669)	(1,419)
Net assets		20,798	22,839
Shareholders' equity
Called-up share capital	20	304	304
Share premium		22,663	22,663
Share based payments reserve	21	463	294
Retained earnings		(2,975)	(916)
Foreign exchange reserve		343	494
Total equity attributable to equity holders of the parent		20,798	22,839

COMPANY STATEMENT OF FINANCIAL POSITION AS AT 31 DECEMBER 2009

 

		As at 31 December 2009	As at 31 December 2008
	Note	£ 000's	£ 000's
Assets
Non-current assets
Investment in subsidiaries	14	2	1
Trade and other receivables	15	19,291	20,855
Total non current assets		19,293	20,856
Current assets
Trade and other receivables	15	1,048	581
Cash and cash equivalents		26	431
Total current assets		1,074	1,012
Total assets		20,367	21,868
Liabilities
Current liabilities
Trade and other payables	17	(391)	(177)
Borrowings	18	(453)	-
Total liabilities		(844)	(177)
Net assets		19,523	21,691
Shareholders' equity
Called-up share capital	20	304	304
Share premium		22,663	22,663
Share based payments reserve	21	463	294
Retained earnings	26	(3,907)	(1,570)
Total equity attributable to equity holders of the parent		19,523	21,691

GROUP STATEMENT OF CASH FLOWS FOR THE YEAR ENDED 31 DECEMBER 2009

 

	Year ended 31 December 2009	Period 01 September 2007 to 31 December 2008
	£ 000's	£ 000's
Cash outflow from operating activities
Operating (loss)	(105)	(577)
Decrease/(increase) in trade and other receivables	207	(805)
Increase in trade and other payables	864	306
(Increase) in inventory	(39)	(129)
Depreciation	60	119
Amortisation	31	18
Share options expensed	169	675
Income tax paid	(6)	-
Net cash inflow/(outflow) from operating activities	1,181	(393)
Cash flows from investing activities
Interest received	66	153
Payments to acquire intangible assets	(1,857)	(3,910)
Payments to acquire tangible assets	(11)	(74)
Investment in associate	-	(14,544)
Cash acquired on acquisition of subsidiary	-	31
Net cash outflow from investing activities	(1,802)	(18,344)
Cash flows from financing activities
Issue of ordinary share capital	-	16,636
Share issue costs	-	(1,637)
Proceeds from borrowings	453	-
Loan repayments to third parties	-	(1,742)
Net cash inflow from financing activities	453	13,257
Net (decrease) in cash and cash equivalents	(168)	(5,480)
Foreign exchange differences on translation	(173)	298
Cash and cash equivalents at beginning of period	571	5,753
Cash and cash equivalents at end of period	230	571

COMPANY STATEMENT OF CASH FLOWS FOR THE YEAR ENDED 31 DECEMBER 2009

 

	Year ended 31 December 2009	Period 01 September 2007 to 31 December 2008
	£ 000's	£ 000's
Cash outflow from operating activities
Operating (loss)	(727)	(1,363)
(Increase) in trade and other receivables	(467)	(257)
Increase/(decrease) in trade and other payables	214	(11)
Depreciation	-	1
Share based payments expensed	169	675
Income tax paid	(6)	-
Net cash outflow from operating activities	(817)	(955)
Cash flows from investing activities
Interest received	66	153
Loans to subsidiaries	(106)	(19,519)
Payments to acquire tangible assets	-	-
Payments to acquire subsidiaries	(1)	-
Net cash outflow from investing activities	(41)	(19,366)
Cash flows from financing activities
Issue of ordinary share capital	-	16,636
Share issue costs	-	(1,637)
Proceeds from borrowings	453	-
Net cash inflow from financing activities	453	14,999
Net (decrease) in cash and cash equivalents	(405)	(5,322)
Cash and cash equivalents at beginning of period	431	5,753
Cash and cash equivalents at end of period	26	431

 

 STATEMENT OF CHANGES IN EQUITY FOR THE PERIOD ENDED 31 DECEMBER 2009

 

	Called up share capital	Share premium reserve	Share based payments reserve	Retained earnings	Foreign exchange reserve	Total Equity
	£ 000's	£ 000's	£ 000's	£ 000's	£ 000's	£ 000's
Group
As at 31 August 2007	193	6,639	167	(364)	-	6,635
Loss for the year	-	-	-	(552)	-	(552)
Currency translation differences	-	-	-	-	494	494
Total comprehensive income	-	-	-	(552)	494	(58)
Share capital issued	111	17,704	-	-	-	17,815
Cost of share issue	-	(1,680)	-	-	-	(1,680)
Share based payments	-	-	127	-	-	127
As at 31 December 2008	304	22,663	294	(916)	494	22,839
Loss for the year	-	-	-	(2,059)	-	(2,059)
Currency translation differences	-	-	-	-	(151)	(151)
Total comprehensive income	-	-	-	(2,059)	(151)	(2,210)
Share capital issued	-	-	-	-	-	-
Cost of share issue	-	-	-	-	-	-
Share based payments	-	-	169	-	-	169
As at 31 December 2009	304	22,663	463	(2,975)	343	20,798

 

Company
As at 31 August 2007	193	6,639	167	(360)	-	6,639
Loss for the year	-	-	-	(1,210)	-	(1,210)
Total comprehensive income	-	-	-	(1,210)	-	(1,210)
Share capital issued	111	17,704	-	-	-	17,815
Cost of share issue	-	(1,680)	-	-	-	(1,680)
Share based payments	-	-	127	-	-	127
As at 31 December 2008	304	22,663	294	(1,570)	-	21,691
Loss for the year	-	-	-	(2,337)	-	(2,337)
Total comprehensive income	-	-	-	(2,337)	-	(2,337)
Share capital issued	-	-	-	-	-	-
Cost of share issue	-	-	-	-	-	-
Share based payments	-	-	169	-	-	169
As at 31 December 2009	304	22,663	463	(3,907)	-	19,523

 

NOTES TO THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009

 

1	Summary of significant accounting policies
1.01	General information and authorisation of financial statements
	Leni Gas and Oil plc is a public limited company registered in the United Kingdom under the Companies Act 2006. The address of its registered office is level 5, 22 Arlington Street, London, SW1A 1RD. The Company's Ordinary shares are traded on the AIM Market operated by the London Stock Exchange. The Group financial statements of Leni Gas & Oil plc for the period ended 31 December 2009 were authorised for issue by the Board on 11 June 2010 and the balance sheets signed on the Board's behalf by Mr. David Lenigas and Mr. Donald Strang
1.02	Statement of compliance with IFRS
	The Group's financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS). The Company's financial statements have been prepared in accordance with IFRS as adopted by the European Union and as applied in accordance with the provisions of the Companies Act 2006. The principal accounting policies adopted by the Group and Company are set out below.
	New standards and interpretations not applied
	IASB and IFRIC have issued the following standards and interpretations with an effective date after the date of these financial statements:
	International Accounting Standards (IAS / IFRSs) and (Effective date)
	IFRS 2 Amendment to IFRS 2 - Group cash-settled and share-based payment transactions (1 January 2010)
	IFRS 3 Business Combinations - revised January 2008 (1 July 2009)
	IFRS 5 Measurement of non-current assets classified as held-for-sale (1 January 2010)
	IAS 27 Consolidated and Separate Financial Statements - revised January 2008 (1 July 2009)
	IAS 38 Intangible Assets (1 January 2010)
	International Financial Reporting Interpretations Committee (IFRIC)
	IFRIC 17 Distribution of non-cash assets to owners (1 July 2009)

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

1.03	Basis of preparation
	The consolidated financial statements have been prepared on the historical cost basis, except for the measurement to fair value of assets and financial instruments as described in the accounting policies below, and on a going concern basis.
	The financial report is presented in Pound Sterling (£) and all values are rounded to the nearest thousand pounds (£'000) unless otherwise stated.
1.04	Basis of consolidation
	The consolidated financial information incorporates the results of the Company and its subsidiaries ("the Group") using the purchase method. In the consolidated balance sheet, the acquiree's identifiable assets, liabilities are initially recognised at their fair values at the acquisition date. The results of acquired operations are included in the consolidated income statement from the date on which control is obtained. Inter-company transactions and balances between Group companies are eliminated in full.
1.05	Goodwill and intangible assets
	Intangible assets are recorded at cost less eventual amortisation and provision for impairment in value. Goodwill on consolidation is capitalised and shown within non current assets. Positive goodwill is subject to an annual impairment review, and negative goodwill is immediately written-off to the income statement when it arises.
1.06	Oil and gas exploration assets and development/producing assets
	The Group applies the successful efforts method of accounting for oil and gas assets, having regard to the requirements of IFRS 6 'Exploration for and Evaluation of Mineral Resources'.
	All licence acquisition, exploration and evaluation costs are initially capitalised as intangible fixed assets in cost centres by field or by exploration area, as appropriate, pending determination of commerciality of the relevant property. Directly attributable administration costs are capitalised insofar as they relate to specific exploration activities, as are finance costs to the extent they are directly attributable to financing development projects. Pre-licence costs and general exploration costs not specific to any particular licence or prospect are expensed as incurred.
	If prospects are deemed to be impaired ('unsuccessful') on completion of the evaluation, the associated costs are charged to the income statement. If the field is determined to be commercially viable, the attributable costs are transferred to development/production assets within property, plant and equipment in single field cost centres.
	Subsequent expenditure is capitalised only where it either enhances the economic benefits of the development/producing asset or replaces part of the existing development/producing asset.
	Net proceeds from any disposal of an exploration asset are initially credited against the previously capitalised costs. Any surplus proceeds are credited to the income statement. Net proceeds from any disposal of development/producing assets are credited against the previously capitalised cost. A gain or loss on disposal of a development/producing asset is recognised in the income statement to the extent that the net proceeds exceed or are less than the appropriate portion of the net capitalised costs of the asset.

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

1.07	Commercial reserves
	Commercial reserves are proven and probable oil and gas reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50 per cent statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as a proven and probable reserves and a 50 per cent statistical probability that it will be less.
1.08	Depletion and amortisation
	All expenditure carried within each field is amortised from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a field by field basis. In certain circumstances, fields within a single development area may be combined for depletion purposes. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future field development costs necessary to bring the reserves into production. Changes in the estimates of commercial reserves or future field development costs are dealt with prospectively.
1.09	Decommissioning
	Where a material liability for the removal of production facilities and site restoration at the end of the productive life of a field exists, a provision for decommissioning is recognised. The amount recognised is the present value of estimated future expenditure determined in accordance with local conditions and requirements. The cost of the relevant tangible fixed asset is increased with an amount equivalent to the provision and depreciated on a unit of production basis. Changes in estimates are recognised prospectively, with corresponding adjustments to the provision and the associated fixed asset.
1.10	Property, plant and equipment
	Property, plant and equipment is stated in the Balance Sheet at cost less accumulated depreciation and any recognised impairment loss. Depreciation on property, plant and equipment other than exploration and production assets, is provided at rates calculated to write off the cost less estimated residual value of each asset on a straight-line basis over its expected useful economic life of between three and eight years.
1.11	Inventories
	Inventories are stated at the lower of cost and net realisable value. Cost is determined by the weighted average cost formula, where cost is determined from the weighted average of the cost at the beginning of the period and the cost of purchases during the period. Net realisable value represents the estimated selling price less all estimated costs of completion and costs to be incurred in marketing, selling and distribution.
1.12	Revenue recognition
	Revenue represents amounts invoiced in respect of sales of oil and gas exclusive of indirect taxes and excise duties and is recognised on delivery of product. Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount.
1.13	Foreign currencies
	Transactions in foreign currencies are translated at the exchange rate ruling at the date of each transaction. Foreign currency monetary assets and liabilities are retranslated using the exchange rates at the balance sheet date. Gains and losses arising from changes in exchange rates after the date of the transaction are recognised in the income statement. Non‑monetary assets and liabilities that are measured in terms of historical cost in a foreign currency are translated at the exchange rate at the date of the original transaction.
	In the consolidated financial statements, the net assets of the Company are translated into its presentation currency at the rate of exchange at the balance sheet date. Income and expense items are translated at the average rates for the period. The resulting exchange differences are recognised in equity and included in the translation reserve.

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

1.14	Operating leases
	The costs of all operating leases are charged against operating profit on a straight‑line basis at existing rental levels. Incentives to sign operating leases are recognised in the income statement in equal instalments over the term of the lease.
1.15	Financial instruments
	Financial assets and financial liabilities are recognised on the Group's balance sheet when the Group becomes a party to the contractual provisions of the instrument. The Group does not currently utilise derivative financial instruments.
	The particular recognition and measurement methods adopted are disclosed below:
(i)	Cash and cash equivalents
	Cash and cash equivalents comprise cash on hand and demand deposits and other short-term highly liquid investments that are readily convertible to a known amount of cash and are subject to an insignificant risk of changes in value.
(ii)	Trade receivables
	Trade receivables do not carry any interest and are stated at their nominal value as reduced by appropriate allowances for estimated irrecoverable amounts.
(iii)	Trade payables
	Trade payables are not interest-bearing and are stated at their nominal value.
(iv)	Investments
	Investments in subsidiaries are stated at cost and reviewed for impairment if there are indications that the carrying value may not be recoverable.
(v)	Equity investments
	Equity instruments issued by the Company and the Group are recorded at the proceeds received, net of direct issue costs.
1.16	Finance costs
	Borrowing costs are recognised as an expense when incurred
1.17	Borrowings
	Borrowings are recognised initially at fair value, net of any applicable transaction costs incurred. Borrowings are subsequently carried at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the income statement over the period of the borrowings using the effective interest method (if applicable).   Interest on borrowings is accrued as applicable to that class of borrowing. (Note: the company currently does not have any borrowings attracting interest)
1.18	Provisions
	Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.
	When the Group expects some or all of a provision to be reimbursed, for example under an insurance contract, the reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the income statement net of any reimbursement.

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

1.19	Dividends
	Dividends are reported as a movement in equity in the period in which they are approved by the shareholders.
1.20	Taxation
	The tax expense represents the sum of the tax currently payable and deferred tax.
	Current tax, including UK corporation and overseas tax, is provided at amounts expected to be paid (or recovered) using the tax rates and laws that have been enacted or substantially enacted by the balance sheet date.
	Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial information and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the tax profit nor the accounting profit.
	Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, and interests in joint ventures, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future.
	The carrying amount of deferred tax assets is reviewed at each balance sheet date and adjusted to the extent that it is probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.
	Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realised. Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity.
1.21	Impairment of assets
	At each balance sheet date, the Group assesses whether there is any indication that its property, plant and equipment and intangible assets have been impaired. Evaluation, pursuit and exploration assets are also tested for impairment when reclassified to oil and natural gas assets. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment, if any. If it is not possible to estimate the recoverable amount of the individual asset, the recoverable amount of the cash‑generating unit to which the asset belongs is determined.
	The recoverable amount of an asset or a cash‑generating unit is the higher of its fair value less costs to sell and its value in use. The value in use is the present value of the future cash flows expected to be derived from an asset or cash‑generating unit. This present value is discounted using a pre‑tax rate that reflects current market assessments of the time value of money and of the risks specific to the asset, for which future cash flow estimates have not been adjusted. If the recoverable amount of an asset is less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. That reduction is recognised as an impairment loss.
	The Group's impairment policy is to recognise a loss relating to assets carried at cost less any accumulated depreciation or amortisation immediately in the income statement.
	Goodwill acquired in a business combination is, from the acquisition date, allocated to each of the cash‑generating units, or groups of cash‑generating units, that are expected to benefit from the synergies of the combination. Goodwill is tested for impairment at least annually, and whenever there is an indication that the asset may be impaired. An impairment loss is recognised or cash‑generating units, if the recoverable amount of the unit is less than the carrying amount of the unit. The impairment loss is allocated to reduce the carrying amount of the assets of the unit by first reducing the carrying amount of any goodwill allocated to the cash‑generating unit, and then reducing the other assets of the unit, pro rata on the basis of the carrying amount of each asset in the unit.

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

1.22	Impairment of assets (continued)
	If an impairment loss subsequently reverses, the carrying amount of the asset is increased to the revised estimate of its recoverable amount but limited to the carrying amount that would have been determined had no impairment loss been recognised in prior years. A reversal of an impairment loss is recognised in the income statement. Impairment losses on goodwill are not subsequently reversed.
1.23	Share based payments
	Equity settled transactions:
	The Group provides benefits to employees (including senior executives) of the Group in the form of share-based payments, whereby employees render services in exchange for shares or rights over shares (equity-settled transactions).
	The cost of these equity-settled transactions with employees is measured by reference to the fair value of the equity instruments at the date at which they are granted. The fair value is determined by using a Black-Scholes model.
	In valuing equity-settled transactions, no account is taken of any performance conditions, other than conditions linked to the price of the shares of Leni Gas & Oil Plc (market conditions) if applicable.
	The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled, ending on the date on which the relevant employees become fully entitled to the award (the vesting period).
	The cumulative expense recognised for equity-settled transactions at each reporting date until vesting date reflects (i) the extent to which the vesting period has expired and (ii) the Group's best estimate of the number of equity instruments that will ultimately vest. No adjustment is made for the likelihood of market performance conditions being met as the effect of these conditions is included in the determination of fair value at grant date. The Income Statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period.
	No expense is recognised for awards that do not ultimately vest, except for awards where vesting is only conditional upon a market condition.
	If the terms of an equity-settled award are modified, as a minimum an expense is recognised as if the terms had not been modified. In addition, an expense is recognised for any modification that increases the total fair value of the share-based payment arrangement, or is otherwise beneficial to the employee, as measured at the date of modification.
	If an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. However, if a new award is substituted for the cancelled award and designated as a replacement award on the date that it is granted, the cancelled and new award are treated as if they were a modification of the original award, as described in the previous paragraph.
	The dilutive effect, if any, of outstanding options is reflected as additional share dilution in the computation of earnings per share.
1.24	Segmental reporting
	Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the board of directors that makes strategic decisions   The Group has a single business segment: oil and gas exploration, development and production. The business segment can be split into three geographical segments: Spain, Cyprus and UK.
1.25	Share issue expenses and share premium account
	Costs of share issues are written off against the premium arising on the issues of share capital.

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

1.26	Critical accounting estimates and assumptions
	The Group makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions that have a risk of causing material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.
(i)	Recoverability of intangible oil and gas costs
	Costs capitalised as intangible assets are assessed for impairment when circumstances suggest that the carrying value may exceed its recoverable value. This assessment involves judgement as to the likely commerciality of the asset, the future revenues and costs pertaining and the discount rate to be applied for the purposes of deriving a recoverable value.
(ii)	Decommissioning
	The Group has decommissioning obligations in respect of its Spanish asset. The full extent to which the provision is required depends on the legal requirements at the time of decommissioning, the costs and timing of any decommissioning works and the discount rate applied to such costs.
(iii)	Significant accounting estimates and assumptions
	The carrying amounts of certain assets and liabilities are often determined based on estimates and assumptions of future events. The key estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of certain assets and liabilities within the next annual reporting period are:
(iv)	Share-based payment transactions
	The Group measures the cost of equity-settled transactions with employees by reference to the fair value of the equity instruments at the date at which they are granted. The fair value is determined using a Black-Scholes model.
1.27	Earnings per share
	Basic earnings per share is calculated as net profit attributable to members of the parent, adjusted to exclude any costs of servicing equity (other than dividends) and preference share dividends, divided by the weighted average number of ordinary shares, adjusted for any bonus element.
	Diluted earnings per share is calculated as net profit attributable to members of the parent, adjusted for:
(i)	Costs of servicing equity (other than dividends) and preference share dividends;
(ii)	The after tax effect of dividends and interest associated with dilutive potential ordinary shares that have been recognised as expenses; and
(iii)	Other non-discretionary changes in revenues or expenses during the period that would result from the dilution of potential ordinary shares; divided by the weighted average number of ordinary shares and dilutive potential ordinary shares, adjusted for any bonus element.

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

2	Turnover and segmental analysis
	Management has determined the operating segments based on the reports reviewed by the Board of Directors that are used to make strategic decisions.   The Board has determined there is a single business segment: oil and gas exploration, development and production. The business segment can be further split into three geographical segments: Spain, Cyprus and UK.   Spain has been reported as the group's direct oil and gas producing entity, and the group's only revenue generating operation. The UK is the Group's parent and administrative entity and is reported on accordingly.   The board considers the following external reporting to be appropriate to the current development of its strategic investments in Hungary, Malta, Trinidad & Tobago, and USA, all being combined as one reported geographical segment of Cyprus, as the subsidiaries which hold these investments are incorporated therein. Further breakdown of each of these relative country investments is not seen to be informative at this time as a result of their current development stages, and are thus combined and reported under their investment entity.
	Year ended 31 December 2009	UK	Cyprus	Spain	Total
		£'000	£'000	£'000	£'000
	Operating loss by geographical area
	Revenue	-	-	2,133	2,133
	Operating profit/(loss)	(667)	-	562	(105)
	Impairment charge	-	(1,670)	-	(1,670)
	Share of associates' result	-	(344)	-	(344)
	Finance revenue	66	-	-	66
	Profit/(loss) before taxation	(601)	(2,014)	562	(2,053)
	Other information
	Depreciation and amortisation	-	-	91	91
	Capital additions	-	79	1,789	1,868
	Segment assets	-	15,499	6,638	22,137
	Financial assets	507	189	394	1,090
	Cash	26	-	204	230
	Consolidated total assets	533	15,688	7,236	23,457
	Segment liabilities	-	-	-	-
	Trade and other payables	(845)	(5)	(961)	(1,811)
	Provisions	-	-	(858)	(858)
	Consolidated total liabilities	(845)	(5)	(1,819)	(2,669)

 

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

2	Turnover and segmental analysis (continued)

 

	Period 1 September 2007 to 31 December 2008	UK	Cyprus	Spain	Total
		£'000	£'000	£'000	£'000
	Operating loss by geographical area
	Revenue	-	-	2,131	2,131
	Operating profit/(loss)	(1,363)	-	786	(577)
	Share of associates' result	-	(128)	-	(128)
	Finance revenue	153	-	-	153
	Profit/(loss) before taxation	(1,210)	(128)	786	(552)
	Other information
	Depreciation and amortisation	1	-	136	137
	Capital additions	-	2,283	5,121	7,404
	Segment assets	-	17,444	4,985	22,429
	Financial assets	500	378	380	1,258
	Cash	431	-	140	571
	Consolidated total assets	931	17,822	5,505	24,258
	Segment liabilities	-	-	-	-
	Trade and other payables	(177)	-	(317)	(494)
	Provisions	-	-	(925)	(925)
	Consolidated total liabilities	(177)	-	(1,242)	(1,419)

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

3	Operating loss	2009	2008
		£ 000's	£ 000's
	Operating loss is arrived at after charging:
	Auditors' remuneration - audit	15	15
	Auditors' remuneration - non audit services	10	10
	Directors' emoluments - fees and salaries	120	54
	Directors' emoluments - share based payments and options	120	435
	Depreciation	60	119
	Amortisation	31	18
	Auditors' remuneration for non-audit services provided during the period relating to assistance with accounts preparation amounted to £10,000. (2008: £10,000).
4	Employee information	2009	2008
	Staff costs comprised:	£ 000's	£ 000's
	Wages and salaries	630	285
	Social security contributions	155	71
	Total staff costs	785	356
	The average number of employees on a full time equivalent basis during the year was as follows:
		Number	Number
	Administration	3	4
	Operations	11	11
	Total	14	15
5	Taxation	2009	2008
	Analysis of charge in period	£ 000's	£ 000's
	Tax on ordinary activities	6	-
	No taxation has been provided due to losses in the period
	Factors affecting the tax charge for the period:
	Loss on ordinary activities before tax	(2,059)	(552)
	Standard rate of corporation tax in the UK	28%	28.5%
	Loss on ordinary activities multiplied by the standard rate of corporation tax	(577)	(157)
	Effects of:
	Non deductible expenses	-	-
	Withholding tax on overseas interest	(6)	-
	Future tax benefit not brought to account	577	157
	Current tax charge for period	(6)	-
	No deferred tax asset has been recognised because there is uncertainty of the timing of suitable future profits against which they can be recovered.   There are approximately £580,000 (2008: £960,000) of tax losses yet to be utilised by a subsidiary company in Spain. The Spanish tax rate applicable is currently 35%.

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

6	Dividends
	No dividends were paid or proposed by the Directors (2008: nil).
7	Directors' emoluments
				2009	2008
				£ 000's	£ 000's
	Directors' remuneration			772	900
		Directors Fees	Consultancy Fees	Share based payments	Total
	2009	£ 000's	£ 000's	£ 000's	£ 000's
	Executive Directors
	David Lenigas	12	240	-	252
	Fraser Pritchard	12	160	24	196
	Donald Strang	12	156	72	240
	Jeremy Edelman	12	48	24	84
		48	604	120	772
	2008
	Executive Directors
	David Lenigas	16	160	-	176
	Fraser Pritchard (#)	6	75	47	128
	Donald Strang	16	112	312	440
	Jeremy Edelman	16	64	76	156
		54	411	435	900
	No pension benefits are provided for any Director. (#) Fraser Pritchard was appointed on 2 July 2008. During the period a total of £532,000 (2008: £411,000) of consultancy fees, payable by an overseas subsidiary, were accrued to directors (as detailed in Note 24) and were capitalised in accordance with the Group's accounting policies.
8	Loss per share
	The calculation of loss per share is based on the loss after taxation divided by the weighted average number of share in issue during the period:
				2009	2008
	Net loss after taxation (£000's)			(2,059)	(552)
	Weighted average number of ordinary shares used in calculating basic loss per share (millions)			608.3	472.8
	Weighted average number of ordinary shares used in calculating diluted loss per share (millions)			612.6	533.4
	Basic loss per share (expressed in pence)			(0.34)	(0.12)
	Diluted loss per share (expressed in pence)			(0.34)	(0.12)
	As inclusion of the potential ordinary shares would result in a decrease in the loss per share they are considered to be anti-dilutive, as such, a diluted earnings per share is not included.

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

9	Finance revenue	2009	2008
		£ 000's	£ 000's
	Bank interest receivable	1	153
	Interest income on loan to associate	65	-
		66	153
10	Intangible assets		2009
	Group		£ 000's
	Cost
	As at 1 January 2009		7,551
	Additions		1,857
	As at 31 December 2009		9,408
	Amortisation
	As at 1 January 2009		18
	Amortisation		31
	Impairment charge		1,670
	As at 31 December 2009		1,719
	Net book value
	As at 31 December 2009		7,689
	As at 31 December 2008		7,533
		2009	2008
		£ 000's	£ 000's
	The net book value is analysed as follows:
	Oil and gas properties	5,402	3,583
	Deferred exploration expenditure	1,436	3,029
	Decommissioning costs	851	921
		7,689	7,533
	Impairment review
	At 31 December 2009, the Directors have carried out an impairment review and confirmed that the only provision currently required is in relation to the costs associated with the Hungarian projects. (See note 12)

 

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

11	Property, plant and equipment		2009
	Group		£ 000's
	Cost
	As at 1 January 2009		598
	Additions		11
	Disposals		-
	Foreign exchange difference on translation		(45)
	As at 31 December 2009		564
	Depreciation
	As at 1 January 2009		118
	Depreciation		60
	Eliminated on disposal		-
	As at 31 December 2009		178
	Net book value		£'000
	As at 31 December 2009		386
	As at 31 December 2008		480
	Impairment review
	At 31 December 2009, the Directors have carried out an impairment review and confirmed that no provision is currently required.
12	Impairment charge
	During the year, the directors impaired the value of the Group's investments in Hungary (14.54% of ZalaGasCo Kft and 7.27% of PetroHungaria Kft) which was held by Leni Gas and Oil Investments Ltd, a Cyprus registered company owned 100% by the Group. The Company had assessed both investments in detail with the Company's geotechnical provider, Equipoise, and production technology provider, Eclipse Petroleum Technology Ltd ("Eclipse"), and concluded both ZalaGasCo and PetroHungaria ventures will not provide a material return on the Company's investment of £1.67 million for Hungary. The Company announced its decision to relinquish its acreage in both ZalaGasCo and PetroHungaria and write off all of the acquisition and development costs capitalised to date amounting to approximately £1.67 million, on 5 March 2010. (see note 25).

 

13	Interest in associate
	Group					£ 000's
	Cost
	As at 1 January 2009					14,416
	Additions					-
	Share of associate's loss for the period					(344)
	As at 31 December 2009					14,072
	The breakdown of the carrying values at the balance sheet date of the Group's interest in the unlisted associate is as follows:
					Carrying Value	Fair Value
					£ 000's	£ 000's
	Byron Energy Pty Ltd				14,072	14,072
	The directors are of the view that this carrying value is reflective of the estimated current market value, and no impairment is required.
	Details of the Group's associate at 31 December 2009 are as follows:
	Name	Place of incorporation	Proportion held	Date associate interest acquired	Reporting date of associate	Principal activities
	Byron Energy Pty Ltd	Australia	28.94%	2 July 2008	30 June 20009	Oil exploration and production

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

14	Investment in subsidiaries							2009
	Shares in Group undertaking							£ 000's
	Company
	Cost
	As at 1 January 2009							1
	Additions							1
	As at 31 December 2009							2
	The parent company of the Group holds more than 20% of the share capital of the following companies:
	Company		Country of Registration	Proportion held		Nature of business
	Direct
	Leni Gas & Oil Holdings Ltd		Cyprus	100%		Holding Company
	Leni Trinidad Ltd		Trinidad & Tobago	100%		Investment Company
	Indirect
	Via Leni Gas & Oil Holdings Ltd
	Leni Gas & Oil Investments Ltd		Cyprus	100%		Investment Company
	Leni Investments Cps Ltd		Cyprus	100%		Investment Company
	Leni Investments Byron Ltd		Cyprus	100%		Investment Company
	Leni Investments Trinidad Ltd		Cyprus	100%		Investment Company
	Via Leni Investments Cps Ltd
	Compania Petrolifera de Sedano S.L.		Spain	100%		Oil and Gas Production and Exploration Company
	Via Leni Investments Byron Ltd
	Byron Energy Pty Ltd		Australia	28.94%		Oil and Gas Production and Exploration Company
	Leni Gas and Oil US Inc.		United States	100%		Investment Company
	Leni Investments Byron Ltd acquired 100% of the share capital of Leni Gas and Oil US Inc. on 3 August 2009. The company was incorporated on 3 August 2009. Leni Gas and Oil Plc acquired 100% of the share capital of Leni Trinidad Ltd on 20 November 2009. The company was incorporated on 20 November 2009.
15	Trade and other receivables	2009					2008
		Group			Company		Group	Company
		£ 000's			£ 000's		£ 000's	£ 000's
	Current trade and other receivables
	Trade receivables	210			-		177	-
	VAT receivable	12			12		28	28
	Other receivables	482			1,007		413	474
	Prepayments	218			29		511	79
	Total	922			1,048		1,129	581
	Non current trade and other receivables
	Loans due from subsidiaries	-			19,291		-	20,855
	Total	-			19,291		-	20,855
	The loans due from subsidiaries are interest free and have no fixed repayment date.

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

16	Inventories	2009		2008
		Group	Company	Group	Company
		£ 000's	£ 000's	£ 000's	£ 000's
	Inventories - Crude Oil	168	-	129	-
17	Trade and other payables	2009		2008
		Group	Company	Group	Company
		£ 000's	£ 000's	£ 000's	£ 000's
	Current trade and other payables
	Trade Payables	520	240	212	152
	Accruals	838	151	282	25
	Total	1,358	391	494	177
18	Borrowings	2009		2008
		Group	Company	Group	Company
		£ 000's	£ 000's	£ 000's	£ 000's
	Current
	Loans - other (unsecured)	333	333	-	-
	Loans from Directors (unsecured)	120	120	-	-
		453	453	-	-
	The loans due to directors, and other parties are interest free and have no fixed repayment date. The carrying amounts of short-term borrowings approximate their fair value, and are all denominated in pounds sterling.
19	Provisions	2009		2008
		Group	Company	Group	Company
		£ 000's	£ 000's	£ 000's	£ 000's
	Provision for decommissioning costs	858	-	925	-
	These costs relate to the estimated liability for removal of Spanish production facilities and site restoration at the end of the production life of the facilities.
20	Share capital
	Authorised			Number of shares	Nominal value (£000's)
	Ordinary shares of 0.05p each			5,000,000,000	2,500
	Called up, allotted, issued and fully paid			Number of shares	Nominal value (£000's)
	Incorporation			2	-
	17 August 2006 for cash at 0.05p per share			183,999,998	92
	8 February 2007 for cash at 0.05p per share			20,000,000	10
	16 March 2007 for cash at 3p per share			125,233,361	63
	16 March 2007 for cash at 3p per share			500,000	-
	24 August 2007 for cash at 6p per share			55,666,666	28
	15 November 2007 - non cash to acquire 88.75% of a Spanish project			8,000,000	4
	11 December 2007 - non cash for readmission costs			593,793	-
	9 June 2008 - non cash for staff incentives			6,333,333	3
	27 June 2008 for cash at 8p per share			156,725,000	78
	2 July 2008 for cash at 8p per share			19,252,812	10
	29 July 2008 for cash at 8p per share			31,750,000	16
	16 October 2008 cash at 8p per warrants			200,000	-
	As at 31 December 2009			608,254,965	304
	During the period no shares were issued (2008: 214.3 million).

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

20	Share capital (continued)
	Total share options in issue
	During the period no options were issued (2008: 16.3 million).
	As at 31 December 2009 the options in issue were:
	Exercise Price			Expiry Date				Options in Issue 31 December 2009
	3p			16 March 2012				16,000,000
	5p			9 June 2013				16,300,000
								32,300,000
	No options lapsed or were cancelled and no options were exercised during the period.
	The above 5p options were granted on 9 June 2008 and will vest 50% each at the first and second anniversary of the grant date.
	Total warrants in issue
	During the period, no warrants were issued (2008: 103.9 million)
	As at 31 December 2009 the warrants in issue were;
	Exercise Price			Expiry Date				Warrants in Issue 31 December 2009
	8p			26 June 2013				78,362,500
	8p			1 July 2013				9,426,406
	8p			28 July 2013				15,875,000
								103,663,906
	No warrants lapsed or were cancelled in the period. No warrants were exercised during the period (2008: 0.2 million).
21	Share based payment arrangements
	Share options
	During 2008, the Company established an employee share option plan to enable the issue of options as part of remuneration of key management personnel and Directors to enable the purchase of shares in the entity. Options were granted under the plan for no consideration. Options were granted for a five year period. There are vesting conditions associated with the options. Options granted under the plan carry no dividend or voting rights.
	Under IFRS 2 'Share Based Payments', the Company determines the fair value of options issued to Directors and Employees as remuneration and recognises the amount as an expense in the income statement with a corresponding increase in equity.
	Name	Date Granted	Vesting Date		Number	Exercise Price (pence)	Expiry Date		Fair Value at Grant Date (pence)	Fair Value after discount (pence)
	Jeremy Edelman	9 June 2008	9 June 2009		1,000,000	5	9 June 2013		2.39	2.39
	Jeremy Edelman	9 June 2008	9 June 2010		1,000,000	5	9 June 2013		2.39	2.39
	Donald Strang	9 June 2008	9 June 2009		3,000,000	5	9 June 2013		2.39	2.39
	Donald Strang	9 June 2008	9 June 2010		3,000,000	5	9 June 2013		2.39	2.39
	Fraser Pritchard	9 June 2008	9 June 2009		1,000,000	5	9 June 2013		2.39	2.39
	Fraser Pritchard	9 June 2008	9 June 2010		1,000,000	5	9 June 2013		2.39	2.39
	Staff	9 June 2008	9 June 2009		3,150,000	5	9 June 2013		2.39	1.91
	Staff	9 June 2008	9 June 2010		3,150,000	5	9 June 2013		2.39	1.91
	Totals				16,300,000
	The fair value of the options vested during the period was £169,000 (2008: £127,000). The assessed fair value at grant date is determined using the Black-Scholes Model that takes into account the exercise price, the term of the option, the share price at grant date, the expected price volatility of the underlying share, the expected dividend yield and the risk-free interest rate for the term of the option.

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

21	Share based payment arrangements (continued)
	The following table lists the inputs to the model used for the period ended 31 December 2009:
	Dividend Yield (%)		-
	Expected Volatility (%)		190
	Risk-free interest rate (%)		2
	Share price at grant date (pence)		2.5
	The expected volatility reflects the assumption that the historical volatility is indicative of future trends, which may, not necessarily be the actual outcome. A discount factor of 80% has been applied to the value of the options issued to staff.
22	Financial instruments
	The Group uses financial instruments comprising cash, and debtors/creditors that arise from its operations. The Group holds cash as a liquid resource to fund the obligations of the Group. The Group's cash balances are predominantly held in Sterling. The Group's strategy for managing cash is to maximise interest income whilst ensuring its availability to match the profile of the Group's expenditure. This is achieved by regular monitoring of interest rates and monthly review of expenditure forecasts.   The Company has a policy of not hedging and therefore takes market rates in respect of foreign exchange risk; however it does review its currency exposures on an ad hoc basis. Currency exposures relating to monetary assets held by foreign operations are included within the foreign exchange reserve in the Group Balance Sheet.   The Group considers the credit ratings of banks in which it holds funds in order to reduce exposure to credit risk.   To date the Group has relied upon equity funding to finance operations. The Directors are confident that adequate cash resources exist to finance operations to commercial exploitation but controls over expenditure are carefully managed.   The net fair value of financial assets and liabilities approximates the carrying values disclosed in the financial statements. The currency and interest rate profile of the financial assets is as follows:
	Cash and short term deposits					2009		2008
						£ 000's		£ 000's
	Sterling					26		430
	US Dollars					-		1
	Euros					204		140
						230		571
	The financial assets comprise cash balances in interest earning bank accounts at call. The financial assets in Sterling currently earn interest at the base rate set by the Bank of England less 0.15%
	Foreign currency risk
	The following table details the Group's sensitivity to a 10% increase and decrease in the Pound Sterling against the relevant foreign currencies of Euro, US Dollar. 10% represents management's assessment of the reasonably possible change in foreign exchange rates.   The sensitivity analysis includes only outstanding foreign currency denominated investments and other financial assets and liabilities and adjusts their translation at the period end for a 10% change in foreign currency rates. The following table sets out the potential exposure, where the 10% increase or decrease refers to a strengthening or weakening of the Pound Sterling:
		Profit or loss sensitivity			Equity sensitivity
		10% increase		10% decrease	10% increase		10% decrease
		$ 000's		$ 000's	$ 000's		$ 000's
	Euro	(67)		55	(301)		368
	US Dollar	(33)		34	(33)		34
		(100)		89	(334)		402

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

 

22			Financial instruments (continued)
			Foreign currency risk (continued)
			Rates of exchange to £1 used in the financial statements were as follows:
				As at 31 December 2009	Average for the relevant consolidated period to 31 December 2009		As at 31 December 2008		Average for the period to 31 December 2008
			Euro	1.1113	1.1215		1.0272		1.3005
			US Dollar	1.5928	1.5597		1.4479		1.7350
23			Commitments
			As at 31 December 2009, the Company had entered into the following material commitments:
			The Company signed a deed of Amendment and Assignment Agreement with Malta Oil Pty Limited, a subsidiary of Mediterranean Oil and Gas plc in July 2008 to acquire 10% participating interest in a production sharing contract. Minimum expenditure for the Company under this agreement is approximately US$ 500,000.
			Exploration commitments
			Ongoing exploration expenditure is required to maintain title to the Group's mineral exploration permits. No provision has been made in the financial statements for these amounts as the expenditure is expected to be fulfilled in the normal course of the operations of the Group.
	24	Related party transactions
		Transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note. Transactions between other related parties are discussed below.   During the period, the Company accrued the following consultancy fees to the Company's directors for work performed in relation to an overseas subsidiary. These fees have been recharged to this subsidiary as follows : (i) £228,000 to David Lenigas (2008:£160,000), (ii) Nil to Jeremy Edelman (2008:£64,000), (iii) £144,000 to Donald Strang (2008:£112,000, (iv) £160,000 to Fraser Pritchard (2008:£75,000). (v) Total accrued £532,000 (2008:£411,000).   During the period, two directors made loans to the parent company, these loans remain fully outstanding at the end of the year. The loans were made unsecured, with no fixed repayment period and non-interest bearing. The loans from directors outstanding as at 31 December 2009 are; (i) £35,000 from Donald Strang (2008:£Nil), (ii) £85,000 from Jeremy Edelman (2008:£Nil), (iii) Total outstanding £120,000 (2008:£Nil).
		Remuneration of Key Management Personnel The remuneration of the Directors and other key management personnel of the Group is set out below in aggregate for each of the categories specified in IAS24 Related party Disclosures.
						2009		2008
						£ 000's		£ 000's
		Short-term employee benefits				294		100
		Share-based payments				133		448
						424		548

NOTES TO FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2009 (CONTINUED)

25	Post balance sheet events
	On 25 January 2010, the Company announced, that it had completed the agreement to convert the Company's investment in Byron Energy to direct working interests and options in the Gulf of Mexico and Gulf Coast acreage. The direct working interests are now held directly by one of the Group's subsidiaries Leni Gas & Oil Inc. (a USA incorporated company).   On 5 March 2010, the Company announced that it had decided to relinquish all of its investments in Hungary.
26	Profit and loss account of the parent company
	As permitted by section 408 of the Companies Act 2006, the profit and loss account of the parent company has not been separately presented in these accounts. The parent company loss for the period was £2.337 million (2008: £1.210 million).

 

Note to the announcement:

The summary accounts set out above do not constitute statutory accounts as defined in Section 435 of the Companies Act 2006 in respect of the 2009 Accounts or by Section 240 of the Companies Act 1985 in respect of the Accounts for the period of 1 September 2007 to 31 December 2008. The auditor's report on the statutory financial statements for the year ended 31 December 2009 and for the period of 1 September 2007 to 31 December 2008 were unqualified and did not contain any statement under Section 498(2) or (3) of the Companies Act 2006.