27th Apr 2009 13:21
For Immediate Release
27 April 2009
LENI GAS AND OIL PLC
("LGO" or the "Company")
Annual Report and Accounts
Leni Gas and Oil plc is pleased to announce its audited Annual Report and Accounts for the 16 months ended 31 December 2008. These will be posted to Shareholders on 29 April 2009 and a copy of this announcement and the Annual Report and Accounts is available from the Company's website, www.lenigasandoil.co.uk.
Highlights
FINANCIALS
Pre-tax operating profit before amortisation from Spain of £923,000
Pre-tax group loss of £552,000, mainly attributable to a non-cash item of £675,000 relating to share based payments
Strong balance sheet with net current assets of £1.3 million
OPERATIONS
Development drilling in the US Gulf of Mexico [via interests in Byron Energy Pty Ltd ("Byron Energy")] successfully completed the Eugene Island development program with three wells tested at gross production rates of 1,750 boepd, 4,012 boepd and 2,557 boepd
Total stabilised production from the Eugene Island development is 6,000 boepd gross (effective LGO production of 435 boepd) with LGO production approximately 57,300 bbls of oil equivalent to 31 March 2009
Three further developments in the US Gulf of Mexico portfolio are planned for 2009 by Byron Energy
Production from Ayoluengo oilfield in Spain totalled 81,317 barrels of oil equivalent to 31 March 2009
A revised recoverable reserves interpretation was completed on Ayoluengo identifying 93 million bbls of oil remaining in place across four undepleted oil zones with average field historical recovery of only 15%
A five phase production enhancement program was initiated on the Ayoluengo oilfield targeting incremental recoverable reserves of 15 million barrels of oil equivalent by boosting primary and secondary recovery from the undepleted oil zones
Initial results of the Ayoluengo production enhancement program increased historical average production levels by nearly 300%
A major re-interpretation of all the Spanish exploration acreage was completed and identified recoverable prospective and contingent resources across 10 prospects with total unrisked mean volume of 12.8 mmboe gross (LGO 85%). These prospective and contingent resources are in addition to the recoverable reserves target from Ayoluengo of 15 mmbo
Four of the ten largest Spanish exploration prospects are undergoing appraisal for possible tie-back to production from Ayoluengo in 2010
Trinidad production totalled 6,899 bbls of oil to 31 March 2009
A production enhancement program in Trinidad is underway to increase well productivity and exploit the additional shallow undepleted zones with survey of the deeper potential under investigation
First gas production from the Hungarian gas development Penészlek commenced and produced gross 0.5 bcf (net to LGO) during the reporting period
The second stage of Penészlek development was defined from interpreting a new 3D seismic survey across the development area and identified contingent resources of 2.57 bcf gross (LGO 7.27%) and prospective resources of 4.65 bcf gross (LGO 7.27%) across five new locations, with the first of five new drilling locations testing at 2.5 mmscfd gross
The field development plan for the second Hungarian gas development, ZalaGas, was finalised with the other venture partners and MOL after completing a wide scope well stimulation and reservoir measurement program
The Malta acreage Exploration Study was finalised and a new Production Sharing Contract signed with the venture partners and the Maltese Government. A work program was approved and commenced 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
CORPORATE
Acquisition of 22.3% in Byron Energy which operates as an oil & gas exploration, development and production company focused on opportunities in the US Gulf of Mexico and Gulf Coast. The interests were increased to 28.94% in August 2008
Acquisition of the producing Ayoluengo oil field, north-west Spain. Initial acquisition of 88.75% interest which was increased to 100% in April 2008
Increased equity in Spanish exploration acreage to 85% from 50% in April 2008
Acquisition of 7.27% equity interest in two Hungary gas developments, the Penészlek gas development in eastern Hungary, and the ZalaGas joint venture with MOL in the west of Hungary
Acquisition of 50% interest in Trinidad onshore mature producing asset, in highly prospective East Venezuelan Basin
Submitted bid on a second onshore mature producing asset in onshore eastern Trinidad
Reduction of equity in the Malta Area 4 acreage from 20% to 10% with commensurate reduction in funding commitments
Completion of a Heads of Agreement with Byron Energy in April 2009 to transfer the Company's shareholding from an indirect to a direct working interest ownership of the US Gulf of Mexico and Gulf Coast oil and gas assets and an opportunity for portfolio expansion
TARGETS
Completing the transfer agreement with Byron Energy to assume a direct working interest in all Gulf of Mexico and Gulf Coast properties
Expanding production from the Eugene Island development by increasing production capacity
Initiating other developments covered under the Byron Energy / Leed Petroleum Plc agreement on Sorrento, Ship Shoal and South Marsh Island properties
Completing four out of five production enhancement programs on the Ayoluengo oilfield in Spain through maximizing primary and secondary recovery in the undepleted oil zones to increase production to near 1,500 bopd
Finalising infill drilling development plans for 2010 for maximizing Ayoluengo oilfield production to target the 15 million bbls of oil incremental reserves
Appraising four of the ten exploration prospects surrounding the Ayoluengo oilfield and developing an exploitation program to tie-back these prospects in 2010
Concluding the production enhancement program in Trinidad to step change well productivity and identify infill wells for targeting the shallow "sweet spot" reserves and potential deeper reserves
Increasing gas production in Hungary through developing the additional prospects in the Penészlek gas development area and connecting to the existing production infrastructure and implementing the ZalaGas re-development work program
Completing the second stage work program in Malta to increase the understanding and chance of success on the identified drilling prospects for campaigning in 2010
Continue to assess and convert value adding acquisitions to complement the Company's strategy
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.
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 this reporting period, the Company has significantly increased its portfolio of oil and gas production assets, with acquisitions in the US Gulf of Mexico, Spain, Trinidad and Hungary and an investment revision in Malta. All acquisitions have existing or near term production with considerable upside potential for significant incremental recoverable reserves. The Company's strategy to acquire and enhance existing production assets with additional exploitation potential remains unchanged, and is continuing to actively pursue similar opportunities to increase both the equity position of existing assets, as well as identify additional similar assets for acquisition.
Since the last full reporting period, the Company has concluded a significant acquisition in the US Gulf of Mexico through its acquisition of 28.94% of Byron Energy which has interests via an agreement with Leed Petroleum Plc to develop multiple shallow water oil and gas assets offshore and onshore USA, and recently executed a heads of agreement to convert this interest into a direct asset working interest.
The Eugene Island asset was the first of these interests to be developed and during the reporting period three wells were developed and placed on production. Between October 2008 and February 2009, the A-6 recompletion, A-7 and A-8 wells were completed and successfully tested at gross rates of 1,750 boepd, 4,012 boepd and 2,557 boepd respectively. At the end of the three well development programme in February 2009, total production through the Eugene Island production platform was 6,000 boepd gross, at 2,500 bbls of oil and 21 mmscfd of gas, as reported by the joint venture operator in February 2009.
Shortly after the end of the Eugene Island development, 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. This agreement converts the interest in Byron Energy to a direct working interest in Eugene Island equating to direct production and sales to LGO of approximately 435 boepd.
The agreement also includes the conversion of LGO's shareholding in Byron Energy to acquire up to 29% of Byron Energy's interest in all option properties in the GoM under the existing Leed Petroleum Plc / Byron Scouting Agreement, as well as the option to acquire up to a 20% direct working interest in properties acquired by Byron Energy outside of the Leed agreement with effect from end 2008 by paying 30% of all costs.
Also since the last reporting period, the Company has validated the potential of the first production asset in Spain by way of acquiring 100% of the operational Ayoluengo oilfield in Spain and has embarked on an ambitious production enhancement program to realise 15 million barrels of incremental recoverable reserves and increase production to near 2,500 barrels of oil per day through a five stage enhanced recovery program.
Two of the five enhancement programs were initiated in late October 2008 with commencement of water injection at 1600 bwpd into the deeper reservoir zones and the first of two phases of field Stimulation. Initial results of the Phase 1 Stimulation program in December 2008 realised a total production increment of 170% on the historical average pre-perforation production levels to a new average of 300 bopd. An overall production of near 500 bopd by completion of the program in mid Q2 2009 is targeted.
During the remainder of 2009, four of the five planned enhancement programs are due for completion. The Stimulation programs are set to improve production efficiency and well productivity. The expansion of the Water Injection facilities should triple injection rates hence adding to overall oil production from the field. The execution of a large perforation campaign later in the year is to target 400m of undepleted reservoir zones which will also increase oil production. The combination of these programs is targeting minimum production levels of 1,500 bopd by the end of 2009 with a stretch target of 2,000 bopd. An infill drilling program is planned for end Q1 2010 to increase production near the 2,500 bopd overall field target.
The surrounding exploration acreage in Spain (Basconcillos H, Huermeces and Valderredible permits) also show significant potential for additional near-term developments, and the Company's technical team conducted an area wide re-interpretation to develop a fast-track exploitation program. To this extent, the Company increased its holding in these permits from 50% to 85% during the period.
In total 10 prospects (of which two are historical oil discoveries and one a gas discovery not previously assessed) were identified across the acreage with a total unrisked mean gross STOIIP of 74 mmb and gross GIIP of 4bcf. The recoverable prospective and contingent resources across the 10 prospects have a total unrisked mean volume of gross 12.8 mmboe (LGO 85%). These prospective and contingent resources are in addition to the recoverable reserves target from Ayoluengo of 15.0 mmboe.
Further to the re-interpretation of the 10 prospects, four with greatest potential have been identified for either extended well testing or detailed imaging surveys in order to accelerate near term development in 2010. The 2009 work program shall focus on appraising these four prospects and developing the optimum exploitation plan.
Also in Spain, the Company signed an innovative agreement with a Spanish Government Foundation to commence the investigate of Carbon Capture and Storage Enhanced Oil Recovery sites, and in early 2009 signed a joint development agreement to commence work programs on the western flank of Ayoluengo and the Huermeces licence. This project has the potential to considerably boost production from both of these areas through successful CO2 flood tertiary oil recovery.
The Company also acquired a 50% interest in the producing Icacos oilfield in Southern Trinidad by way of exercising an option agreement in January 2008. The field is jointly owned with the operator of the field, Primera Oil. The acquisition of 50% of the producing Icacos oilfield in Trinidad provides the Company with a foothold in one of the richest oil and gas bearing areas of the world and access to the highly prospective East Venezuelan Basin.
In order to step change the existing production of the Icacos asset, and validate the magnitude of the prospective deeper reserves, the Company undertook a review of the Icacos oilfield to establish recoverable reserve potential and define production enhancement programs similar to those planned in Spain. These work programs shall continue during 2009 and shall focus on maximising well productivity and production infrastructure efficiency with the execution of imaging surveys to identify both shallow and deep development opportunities for infill drilling and deep exploitation.
So far during 2009, the production enhancement programs in Trinidad have stabilized gross production at 40 bopd (LGO 50%), an increase of 30% since acquisition, and further expansion is planned. The Company also submitted a bid for a second mature redevelopment asset in onshore eastern Trinidad.
In Hungary, the Company has brought onstream with joint venture partners its first gas production asset in the Penészlek development area and has commenced the second stage of development by identifying halo prospects to connect to the new production infrastructure from a large 3D seismic survey acquired at end 2008.
The results of the seismic interpretation of the Penészlek development area identified five new resources with unrisked mean GIIP totalling 11.27 bcf gross (LGO 7.27%), excluding the resources of the prematurely abandoned Penészlek Miocene field. The total unrisked mean gas resources include two locations totalling contingent resources of 2.57 bcf gross and three locations totalling prospective resources of 4.65 bcf gross.
The first of the contingent resource locations completed sidetrack drilling just before end of the reporting period and successfully tested at 2.5 mmscfd gross with the remaining four locations planned during the remainder of 2009 to substantially increase gas sales revenue from East Hungary.
Also in Hungary, we are working with MOL to define the re-development program for increasing gas recovery from the Bajcsa gasfield. This program has the objective to near double the recovery of the multiple fields covered under the MOL agreement. During the reporting period, the joint venture undertook various field stimulation programs to optimize the re-development program which is now planned for mid 2009.
During the period, the Company has also de-risked the portfolio, by reducing exposure in high risk exploration plays in Malta and Switzerland. In Malta the Company's interest was halved to 10% and a second stage work program commenced 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. The Company's position in Switzerland was relinquished in early 2009.
Over the next reporting period, the Company is planning to substantially increase oil production in the US Gulf of Mexico, Spain, Trinidad and Hungary, develop and plan the execution of major development and production enhancement programs in all of these countries, and identify high potential drilling prospects in Malta.
At the end of the current reporting period, the Company is averaging attributable production over 800 boepd. An increase of over 300% is conservatively targeted by end of the next reporting period with a daily production target of 2,500 boepd from the four countries of producing operations, the majority from Spain and US Gulf of Mexico.
The Company is continually seeking to increase the portfolio value through further acquisitions and strengthening the position in existing assets thereby allowing LGO to optimise exploitation programmes and increase overall production.
The Directors are encouraged by the considerable potential of the portfolio and by the results of the reporting period with production increases of five fold since acquisition and given the high activity levels planned, is looking forward to further enhancement of portfolio value. In line with expectations the Company is reporting:
Pre-tax operating profit before amortisation from Spain of £923,000
Pre-tax group loss of £552,000, mainly attributable to a non-cash item of £675,000 relating to share based payments
Strong balance sheet with net current assets of £1.3 million
Although the market conditions are challenging, the Directors are excited about the prospects for the Company in the year ahead and would like to take this opportunity of thanking all of our staff, employees, consultants and our shareholders for their ongoing support.
David Lenigas
Executive Chairman
27 April 2009
GLOSSARY & NOTES
AIM = London Stock Exchange Alternative Investment Market
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
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
GIIP = Gas Initially In Place
GoM = US Gulf of Mexico and Gulf Coast
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 2005 classification.
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.
In only 2 years since listing it has established a portfolio of proven reserves and producing assets in low risk countries with significant development and enhancement potential and has increased acquisition production levels by five fold in this time using both proven and leading edge oilfield technologies to maximise exploitation.
It operates a low risk portfolio of production expansion assets in the US Gulf of Mexico, Spain, Trinidad, Hungary 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 has managed its portfolio during the period to ensure all assets are either on production or have been considerably enhanced since acquisition whilst also divesting high risk exploration acreage.
A summary of period activity in all countries of operation follows:
US GULF OF MEXICO:
In July 2008 the Company acquired 22.3% of the total issued share capital in Byron Energy Pty Ltd for an aggregate cost of approximately US$22 million in cash. Byron Energy is a private Australian company, incorporated in 2005 and operates as an oil & gas exploration, development and production company focused on opportunities in the US Gulf of Mexico and Gulf Coast.
Byron Energy's primary assets comprise rights granted to oil and gas properties in the shallow waters of the Gulf of Mexico under a scouting agreement (the "Scouting Agreement") with Leed Petroleum plc, a company listed on AiM. Under the Scouting Agreement Byron Energy exclusively presented potential acquisition opportunities and provides additional technical expertise to Leed as required. The Scouting Agreement remained valid and binding until December 2008. In return Byron Energy has been granted rights, exercisable at its discretion for up to one year, to acquire up to 25 per cent (25%) of Leed's working interest in any such acquisition. To date, Byron Energy has been granted these rights in respect of Eugene Island Blocks 172, 183 and 184, Grand Isle Blocks 95 and 100, Ship Shoal Blocks 201 and 205 , South Marsh Island Blocks 5, 6 and 8, Main Pass Block 115 and West Cameron Block 106.
In July 2008, Byron Energy completed a transaction to acquire a 25% Working Interest in both Eugene Island Blocks 183 and the southern half of Block 184 (Net Revenue Interest up to 20.83% in Block 183 and 19.17% in the southern half of Block 184), including the Eugene Island 184A platform and production facilities. Byron Energy also acquired a 12.5% Working Interest (Net Revenue Interest 9.58%) in the northern half Eugene Island Block 184 and 10.37% Working Interest (Net Revenue Interest 8.64%) in Eugene Island Block 172, excluding the Eugene Island 172 producing reserves and platform.
The equity position in Byron Energy was increased in August 2008 through the acquisition of a further 1 million shares from IB Daiwa Corporation, increasing its holding from 22.3 percent (22.3%) of the issued share capital of Byron Energy to 28.94 percent (28.94%) for an aggregate cost of US$6.57 million in cash.
The Eugene Island asset is the first of the Leed interests to be developed and during the reporting period three wells were successfully developed and placed on production. In October 2008, the A-7 well was completed and 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 recompleted at a superior take point identified during A-8 drilling. The A-6 well tested at 1,750 boepd gross, an increase of 1,250 boepd on previous production. At the end of the three well development program in February 2009, total production through the Eugene Island production platform was 6,000 boepd gross, at 2,500 bbls of oil and 21 mmscfd of gas, as reported by the joint venture operator in February 2009.
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 is to convert 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"). LGO's working interest share of Eugene Island Field oil production would equate to direct production and sales to LGO of approximately 435 boepd.
The agreement also includes the conversion of LGO's shareholding in Byron Energy to acquire up to 29% of Byron Energy's interest in all option properties in the GoM under the existing Leed Petroleum Plc / Byron Scouting Agreement. This agreement also includes the Eugene Island block 133 and Ship Shoal block 197 which Leed Petroleum and Byron Energy successful bid in March 2009 under the US Minerals Management Service.
In addition LGO will also have the option to acquire up to a 20% direct working interest in properties acquired by Byron Energy with effect from 8 December 2008 by paying 30% of all costs, such as the West Cameron Area South blocks 489-491 and West Delta Area block 49 which were successful bid by Byron Energy in March 2009 under the US Minerals Management Service lease auction. Both MMS bids by Leed / Byron Energy and separately by Byron Energy are subject to a geological review by the Minerals Management Service to confirm adequacy of bid value.
The consideration for the transaction will continue to be recorded in the Company's accounts as £14.5 million, being the cost of the Company's share acquisition in 2008. In addition LGO agrees to Byron Energy retaining sufficient cash flows from LGO's working interests in the Eugene Island Field until LGO's portion (estimated to be approximately US1.7 million) of Byron Energy's current borrowing of US$6.2 million is repaid.
There are no reserve or resources figures reportable under the transaction, however either separately or in conjunction with Byron Energy, LGO will commission and report the figures at the earliest opportunity including the full production schedule. The precise terms of LGO's interests in the wells will be disclosed when the legal documentation is agreed and finalised including the material rights and obligations under the operating agreements, together with the level of net cash flow being paid directly out of such interests.
The 2009 work programme for the GoM interests shall focus on the re-development of Sorrento, South Marsh Island and Ship Shoal.
Total production from Eugene Island for the period from 01 September 2007 to 31 December 2008 was approximately 19,200 bbls of oil equivalent (8,000 bbls of oil and 67,200 mscf of gas) and until 31 March 2009 was approximately 57,300 bbls of oil equivalent (23,875 bbls of oil and 200,500 mscf of gas). The actual production for the period shall be announced on completion of the agreement with Byron Energy on the indirect to direct ownership conversion.
SPAIN:
In November 2007, the Company acquired the entire issued share capital of Compañía Petrolífera de Sedano, S.L., whose assets include 88.75% in the La Lora production concession (containing the Ayoluengo oil field) in northern Spain and 50% interest in the surrounding exploration permits of Huermeces, Valderredible and Basconcillos H, covering an area of over 554 sq.km.
The equity position in all assets was increased in April 2008, by acquiring the remaining 11.25% of the Ayoluengo oil field in northern Spain from Gold Oil Plc and increased to 85% through a farmout with Tethys Oil A.B., the interests in all the exploration permits.
The Company appointed TRACS International Ltd, the international consulting services company that specialises in the petroleum industry, as technical engineering supplier for all the Spain assets, and subsequent to a full field re-interpretation of the Ayoluengo field, the Company announced in April 2008, the enhanced prospectivity of STOIIP in the range of 93-104-116 mmbo (P90-P50-P10) with a target increased recovery factor of 10%.
In June 2008 a multiple phase production enhanced program for the Ayoluengo oilfield was defined to realise the 10% incremental recovery and boost production above 1000 bopd. This program includes two phases of well stimulation, two phases of water injection and one phase of infill drilling in the shallower pay zones, and shall be executed from Q2 2008 through to mid 2010.
The potential of the Ayoluengo field was increased and the various enhancement programs were refined in December 2008 with completion of an updated production and remaining reserves interpretation of the field. This new interpretation mapped all historical production from the four primary reservoir sands to identify where the enhancement programs would have the greatest benefit by locating the un-depleted zones. The greatest concentration of un-depleted areas is in the northeast part of the field which will be the target for imaging surveys and drilling, with the southeast part of the field targeted for secondary recovery.
The results are summarized as follows:
STOIIP = 109.7 mmbo total, allocated 60.9 mmbo (Sargentes sand), 29.4 mmbo (Ayoluengo sand), 15.8 mmbo (Unit A sand) and 3.6 mmbo (Unit C sand)
Remaining Oil in Place = 92.8 mmbo total (85% of STOIIP) allocated 53.3 mmbo (Sargentes sand), 22.1 mmbo (Ayoluengo sand), 14.4 mmbo (Unit A sand) and 3.0 mmbo (Unit C sand);
Historical Recovery Factors = 15% total allocated 25% (Ayoluengo sand), 14% (Unit C sand), 13% (Sargentes sand) and 9% (Unit A sand)
Based on this new study of remaining oil in place, the historical low depletion in the four primary reservoir sands and the identification of potential new enhanced recovery approaches, LGO increased the potential incremental recovery target from the field from 10% to 15%. This represents an increase of 5 mmbo above the previously stated potential target of 10 mmbo incremental recovery to 15 mmbo.
Two of the five enhancement programs were initiated in late October 2008 with commencement of water injection at 1600 bwpd into the deeper reservoir zones and the first of two phases of field Stimulation. The Phase 1 Stimulation program has five key objectives, including perforating of new and existing zones in five wells, re-configuring water injectors to maximise injectivity, de-scaling the production zone well-bore in all active wells, optimising production equipment efficiency and implementing a long term regime to maximise well bore integrity and remove well fluid impurities. LGO's target production increment for the Phase 1 Stimulation program from all of these activities was 120 bopd.
Initial results from the first stage of the Phase 1 Stimulation program in December 2008 realised a total production increment of over 145 bopd, an increase of 130% on the historical average pre-perforation production levels to a new average of 255 bopd. This was further increased in Q1 2009 with execution of further stages of the Phase 1 Stimulation program to 300 bopd with an overall target of near 500 bopd by completion of the program in mid Q2 2009. These target full program results would deliver incremental production more than threefold larger than the forecast.
During 2009, four of the five planned enhancement programs shall be completed, with completion of the Phase 1 Stimulation program to improve production efficiency and well productivity, expansion of the Water Injection facilities to triple injection rates and execution of a large perforation campaign to target 400m of undepleted reservoir zones. The combination of these programs is targeting minimum production levels of 1500 bopd by the end of 2009 with a stretch target of 2000 bopd. The infill drilling program is planned for end Q1 2010 which is targeting overall field production of 2500 bopd.
The surrounding exploration acreage to the Ayoluengo oilfield (Basconcillos H, Huermeces and Valderredible permits) also show significant potential for additional near-term developments, and the Company's technical team conducted an area wide re-interpretation to develop a fast-track exploitation program. To this extent, the Company increased its holding in these permits from 50% to 85% during the period.
In total 10 prospects (of which two are historical oil discoveries and one a gas discovery not previously assessed) are identified across the acreage with a total unrisked mean gross STOIIP of 74 mmb and gross GIIP of 4bcf (LGO 85%). The total mean contingent oil resources is 1.76 mmbo gross, mean contingent gas resources is 2.9 bcf gross and mean unrisked prospective oil resources is 10.6 mmbo gross.
The recoverable prospective and contingent resources across the 10 prospects have a total unrisked mean volume of 12.8 mmboe gross. These prospective and contingent resources are in addition to the recoverable reserves target from Ayoluengo of 15 mmboe.
Further to the re-interpretation of the 10 prospects, four have been identified for either extended well testing or detailed imaging surveys in order to accelerate near term development in mid 2010. The 2009 work program shall focus on the following four activities:
Basconcillos H (Tozo) : detailed survey to assess near term gas development options
Huermeces (Hontomin) : extended well test to assess commerciality
Valderredible / La Lora (Huidobro) : imaging survey to investigate contingent resources prior to drilling
Valderredible (Ayoluengo NE) : imaging survey to investigate prospective resources prior to drilling
The Huermeces and Valderredible licence areas were reduced in 2009 as part of the licence extension relinquishment process. All prospects identified in both these licence areas are retained within the new boundary areas.
In November 2008, an agreement was signed to commence cooperation with the Fundación Ciudad de la Energia (CIUDEN) for the technical assessment of carbon dioxide (CO2) sequestration and enhanced oil recovery 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. One of CIUDEN's most important technical objectives is research and development (R&D) related to carbon capture and storage (CCS).
This agreement was expanded in March 2009 with the signature of a joint development agreement with CIUDEN for the research, testing and implementation of carbon dioxide (CO2) sequestration pilot sites in Spain. 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 during 2009 and 2010. None of the planned production enhancement programs focus on the western flank of Ayoluengo as all production is produced from the east of the field.
Total oil and gas production for the period 01 September 2007 to 31 December 2008 was 64,286 bbls of oil equivalent (60,508 bbls of oil and 19,584 mscf of gas) and to 31 March 2009 was 81,317 barrels of oil equivalent (77,051 bbls of oil and 22,513 Mscf of gas).
TRINIDAD:
In January 2008, the Company announced it had exercised an option to purchase the entire share capital of Eastern Petroleum Australia Pty Ltd ("Eastern"). Eastern's main asset is a 25% interest in the Icacos oilfield permit, covering 1,900 acres, located on the Cedros Peninsula of Southern Trinidad, within the East Venezuelan Basin. The Company also purchased a further 25% interest in the Icacos permit from Kroes Energy Inc. ("Kroes") giving the Company a total interest of 50% in the field.
The field is jointly owned with the operator of the field, Primera Oil, an active participant in the Trinidad petroleum industry. Current daily production for the field averages 40 barrels per day gross from only 3 of 14 wells, with enhanced production targeted through improving well productivity and executing secondary recovery techniques.
The acquisition of 50% of the producing Icacos oilfield in Trinidad provides the Company with a foothold in one of the richest oil and gas bearing areas of the world and access to the highly prospective East Venezuelan Basin. Initial data analysis of the prospect has identified a potential deep oil & gas play of significant magnitude.
In order to step change the existing production of the Icacos asset and validate the magnitude of the prospective deeper reserves, the Company commissioned TRACS International Limited to undertake an immediate review of the Icacos oilfield to establish STOIIP and recoverable reserve estimates and define production enhancement programs similar to those planned in Spain.
These work programs commenced in and shall continue during 2009 and shall focus on maximising well productivity and production infrastructure efficiency with the execution of imaging surveys to identify both shallow and deep development opportunities for infill drilling and deep exploitation. So far during 2009, the production enhancement programs have stabilized production at 40 bopd gross, an increase of 30% since acquisition.
In March 2009, LGO also bid on another onshore asset in eastern Trinidad under a multiple field auction process managed by Petrotrin, the state oil and gas company of Trinidad. Notification of award of this auction is expected by end Q2 2009.
Total oil and gas production for the period 01 September 2007 to 31 January 2008 was 5,491 bbls of oil and to 31 March 2009 was 6,899 bbls of oil. No gas is produced from Trinidad.
HUNGARY:
In April 2008, the Company agreed conditional terms 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, while ZalaGasCo kft has a joint development agreement with MOL Hungarian Oil & Gas for a 50% interest in tight gasfield redevelopment projects in western Hungary. The acquisition was completed in July 2008.
In August 2008, the Penészlek gas development came onstream with a stabilised gross production of 88,200 cu.m per day (3.12 mmscfd; 520 boepd). This project centred on the development of the Pen-104 discovery that was drilled and tested by PetroHungaria in 2006, with new production facilities installed and production routed through MOL national gas transportation network. In October 2008, a 3D seismic survey covering approximately 100 sq km commenced in order to delineate other gas reserves in the vicinity of Pen-104 including the depleted Penészlek field for tie-back to the new production infrastructure.
The results of the seismic interpretation of the Penészlek Development area was announced in March 2009, where the identified resources are being targeted via five possible drilling locations with unrisked mean GIIP from the five locations totalling 11.27 bcf gross, excluding the resources of the prematurely abandoned Penészlek Miocene field which will be reported in the near term. The total unrisked mean gas resources includes two locations (Pen-104a and Pen-12 appraisal) totalling contingent resources of 2.57 bcf gross and three locations (Pen-9, Pen-12 twin and Pen-102 sidetrack) totalling prospective resources of 4.65 bcf gross.
A work program to develop all five locations in 2009 was provisionally approved by the joint venture partners, and the sidetrack of Pen-104 completed in April 2009. The Pen-104a sidetrack accesses reserves in the higher part of the structure to maximise recovery of the mean contingent resources of 1.1 bcf gross. Based on the historical production of the Pen-104 well since first gas in August 2008, the Pen-104a sidetrack shall target recovery of about 0.6 bcf gross remaining. Completion and testing of the Pen-104a sidetrack concluded in mid April 2009 at rates of 2.5 mmscfd gross and is being placed on gas sales production using the existing processing and transportation infrastructure prior to end April 2009.
After the Pen-104a sidetrack completion the joint venture plan on drilling the Pen-12 appraisal well (Pen-105) next in the schedule. Pen-105 shall be drilled near to Pen-12 which successfully tested gas when originally drilled in 1983 and is anticipated to be significantly higher structurally than Pen-12. Pen-105 will spud approximately late Q2 of this year after the necessary permits and approvals have been acquired. The permitting of the pipeline to tie-in Pen-105 to the Penészlek production infrastructure is underway with the intent of minimizing the time from rig release to the commencement of production.
The joint venture is current assessing appraisal drilling of the Pen-9 resources and shall announce in due course the development plan for all remaining Penészlek Development resources for execution near end 2009.
ZalaGasCo kft retains a 50:50 joint venture with MOL in multiple gasfield re-development projects. A pilot project on the producing Bajcsa gasfield is scheduled with the drilling of horizontal wells into proven productive gas reservoirs. These wells, because they were previously on production, are already connected to the field gas processing facilities and production can start immediately once these wells are completed.
During 2008 various well stimulation and reservoir measurement programs were executed on the multiple Bajcsa reservoir zones in order to monitor reservoir and well performance in order to select the optimum zones and wells for re-entry horizontal drilling and incremental gas production.
The approved 2009 work program for Bajcsa shall undertake a horizontal re-entry in one of the shallow reservoir zones to determine reservoir response. Upon successful exploitation, further re-entries in other Bajcsa reservoir zones are planned to maximise incremental production. This detailed work program is currently being finalised between the joint venture group and MOL with the aim to execute in early Q3 2009.
Total oil and gas production for the period from 01 September 2007 to 31 December 208 was 5,999 bbls of oil equivalent (4 bbls of condensate and 34,188 mscf of has) and to 31 March 2009 was 6,278 barrels of oil equivalent (4 bbls of condensate and 35,860 Mscf of gas).
MALTA:
In June 2008 the Exploration Study on the joint venture with Mediterranean Oil & Gas for Area 4 Blocks 4, 5, 6 and 7 in offshore Southern Malta was completed and in July 2008, the Production Sharing Contract for the Area was signed with the Government of Malta.
The Company varied the terms of the joint venture with MOG in July 2008 and will now contribute a total of a USD 2.5 million (including USD 1.5 million the Company has already sole funded) to the costs MOG has expended on exploring the PSC Area and will earn a 10% working interest in the PSC. This agreement reduces the Company's exposure to this exploration venture to ensure funds are focused on current and future production enhancement investments.
Four prospects and five leads on the 5,700 square km PSC Area have been delineated. The total most likely hydrocarbon potential of the PSC Area is 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.
In October 2008 the work program for 2009 was approved with the Government of Malta. The objective of the 2009 work program is 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.
The Work Program will parallel several activities to assess the feasibility of and acquire electromagnetic and gravity data, execute depth re-processing on the acquired 3D seismic and acquire and interpret non-seismic data. The 2009 Work Program has a gross budget cost of 2.5 mmUSD with LGO contributing 250 mUSD.
SWITZERLAND:
The investment in the Hungary assets resulted as a variation in the option to acquire a 10% interest in Ascent's 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.
Finance Review
Economic environment
2008 was a turbulent year for the world economy and for oil and gas prices in particular. Brent opened the year at US$97 per barrel(bbl), reached a peak of US$147/bbl in July 2008, before falling back to end the year at US$35/bbl. The early part of 2009 has seen continued volatility but prices have recovered to around $45/bbl on average.
Results for the period
2008 marked a real turning point in the evolution of Leni Gas and Oil plc. Encouraging production increases arose from developing our Spanish, Hungary and Trinidad operations. Capital placements occurred in June/July 2008 which enabled the Company to secure an interest in production arising from Gulf of Mexico 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 £1.09 million and an operating loss after tax of £0.55 million for the period ended 31 December 2008 mainly attributable to charges of £0.67 million for non-cash share based payments.
Turnover in the period of £2.13 million arose mainly from Spanish oil and gas sales.
Cash flow
Cash flow from operating activities before movements in working capital amounted to £0.23 million. After working capital items, net cash outflow from operating activities was £0.39 million. Net cash inflow from financing activities was £13.25 million mainly attributable to the share placements in June/July 2008. Net cash outflow from investing activities was £18.34 million of which £14.54 million was an investment in an associate (Byron Energy) and £3.91 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 2008 was £0.57 million. Net current assets were £1.33 million.
This will contribute substantially towards the financing of LGO's development program over the next few years.
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 and development 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 the 2009 Annual report.
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.
Financial Statements
GROUP INCOME STATEMENTFOR THE PERIOD ENDED 31 DECEMBER 2008
|
Period 01 September 2007 to 31 December 2008 |
Period 09 August 2006 to 31 August 2007 |
||
|
Notes |
£ 000's |
£ 000's |
|
|
Revenue |
2 |
2,131 |
- |
|
Cost of sales |
(1,040) |
- |
|
|
Gross profit |
1,091 |
- |
|
|
Administrative expenses |
3 |
(993) |
(256) |
|
Share based payments |
(675) |
(167) |
|
|
Operating loss |
(577) |
(423) |
|
|
Share of associate's results |
(128) |
- |
|
|
Finance revenue |
153 |
59 |
|
|
Loss on ordinary activities before taxation |
(552) |
(364) |
|
|
Income tax expense |
5 |
- |
- |
|
Loss on ordinary activities after taxation |
(552) |
(364) |
|
|
Retained loss for the period |
(552) |
(364) |
|
|
Loss per share (pence) |
|||
|
Basic |
8 |
(0.12) |
(0.14) |
|
Diluted |
8 |
(0.12) |
(0.14) |
|
All of the operations are considered to be continuing. |
GROUP BALANCE SHEET AS AT 31 DECEMBER 2008
|
As at 31 December 2008 |
As at 31 August 2007 |
||
|
Note |
£ 000's |
£ 000's |
|
|
Assets |
|||
|
Non-current assets |
|||
|
Intangible assets |
10 |
7,533 |
745 |
|
Tangible assets |
11 |
480 |
1 |
|
Interest in associate |
12 |
14,416 |
- |
|
Total non-current assets |
22,429 |
746 |
|
|
Current assets |
|||
|
Cash and cash equivalents |
571 |
5,753 |
|
|
Trade and other receivables |
14 |
1,129 |
324 |
|
Inventories |
15 |
129 |
- |
|
Total current assets |
1,829 |
6,077 |
|
|
Total assets |
24,258 |
6,823 |
|
|
Liabilities |
|||
|
Current liabilities |
|||
|
Trade and other payables |
16 |
(494) |
(188) |
|
Total current liabilities |
(494) |
(188) |
|
|
Non-current liabilities |
|||
|
Provisions |
17 |
(925) |
- |
|
Total non-current liabilities |
(925) |
- |
|
|
Total liabilities |
(1,419) |
(188) |
|
|
Net assets |
22,839 |
6,635 |
|
|
Shareholders' equity |
|||
|
Called-up share capital |
18 |
304 |
193 |
|
Share premium |
22,663 |
6,639 |
|
|
Share based payments reserve |
19 |
294 |
167 |
|
Retained earnings |
(916) |
(364) |
|
|
Foreign exchange reserve |
494 |
- |
|
|
Total equity attributable to equity holders of the parent |
22,839 |
6,635 |
COMPANY BALANCE SHEET AS AT 31 DECEMBER 2008
|
As at 31 December 2008 |
As at 31 August 2007 |
||
|
Note |
£ 000's |
£ 000's |
|
|
Assets |
|||
|
Non-current assets |
|||
|
Tangible assets |
11 |
- |
1 |
|
Investment in subsidiaries |
13 |
1 |
1 |
|
Trade and other receivables |
14 |
20,855 |
748 |
|
Total non current assets |
20,856 |
750 |
|
|
Current assets |
|||
|
Cash and cash equivalents |
431 |
5,753 |
|
|
Trade and other receivables |
14 |
581 |
324 |
|
Total current assets |
1,012 |
6,077 |
|
|
Total assets |
21,868 |
6,827 |
|
|
Liabilities |
|||
|
Current liabilities |
|||
|
Trade and other payables |
16 |
(177) |
(188) |
|
Total liabilities |
(177) |
(188) |
|
|
Net assets |
21,691 |
6,639 |
|
|
Shareholders' equity |
|||
|
Called-up share capital |
18 |
304 |
193 |
|
Share premium |
22,663 |
6,639 |
|
|
Share based payments reserve |
19 |
294 |
167 |
|
Retained earnings |
(1,570) |
(360) |
|
|
Total equity attributable to equity holders of the parent |
21,691 |
6,639 |
GROUP CASH FLOW STATEMENT FOR THE PERIOD ENDED 31 DECEMBER 2008
|
Period 01 September 2007 to 31 December 2008 |
Period 09 August 2006 to 31 August 2007 |
|
|
£ 000's |
£ 000's |
|
|
Cash outflow from operating activities |
||
|
Operating (loss) |
(577) |
(423) |
|
(Increase) in trade and other receivables |
(805) |
(324) |
|
Increase in trade and other payables |
306 |
188 |
|
(Increase) in inventory |
(129) |
- |
|
Depreciation |
119 |
- |
|
Amortisation |
18 |
- |
|
Share options expensed |
675 |
167 |
|
Net cash outflow from operating activities |
(393) |
(392) |
|
Cash flows from investing activities |
||
|
Interest received |
153 |
59 |
|
Payments to acquire intangible assets |
(3,910) |
(745) |
|
Payments to acquire tangible assets |
(74) |
(1) |
|
Investment in associate |
(14,544) |
|
|
Cash acquired on acquisition of subsidiary |
31 |
- |
|
Net cash outflow from investing activities |
(18,344) |
(687) |
|
Cash flows from financing activities |
||
|
Issue of ordinary share capital |
16,636 |
7,214 |
|
Share issue costs |
(1,637) |
(382) |
|
Loan repayments to third parties |
(1,742) |
- |
|
Net cash inflow from financing activities |
13,257 |
6,832 |
|
Net (decrease)/increase in cash and cash equivalents |
(5,480) |
5,753 |
|
Foreign exchange differences on translation |
298 |
- |
|
Cash and cash equivalents at beginning of period |
5,753 |
- |
|
Cash and cash equivalents at end of period |
571 |
5,753 |
COMPANY CASH FLOW STATEMENT FOR THE PERIOD ENDED 31 DECEMBER 2008
|
Period 01 September 2007 to 31 December 2008 |
Period 09 August 2006 to 31 August 2007 |
|
|
£ 000's |
£ 000's |
|
|
Cash outflow from operating activities |
||
|
Operating (loss) |
(1,363) |
(419) |
|
(Increase) in trade and other receivables |
(257) |
(324) |
|
(Decrease)/increase in trade and other payables |
(11) |
188 |
|
Depreciation |
1 |
- |
|
Share based payments expensed |
675 |
167 |
|
Net cash outflow from operating activities |
(955) |
(388) |
|
Cash flows from investing activities |
||
|
Interest received |
153 |
59 |
|
Loans to subsidiaries |
(19,519) |
(748) |
|
Payments to acquire tangible assets |
- |
(1) |
|
Payments to acquire subsidiaries |
- |
(1) |
|
Net cash outflow from investing activities |
(19,366) |
(691) |
|
Cash flows from financing activities |
||
|
Issue of ordinary share capital |
16,636 |
7,214 |
|
Share issue costs |
(1,637) |
(382) |
|
Net cash inflow from financing activities |
14,999 |
6,832 |
|
Net (decrease)/increase in cash and cash equivalents |
(5,322) |
5,753 |
|
Cash and cash equivalents at beginning of period |
5,753 |
- |
|
Cash and cash equivalents at end of period |
431 |
5,753 |
STATEMENT OF CHANGES IN EQUITY FOR THE PERIOD ENDED 31 DECEMBER 2008
|
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 09 August 2006 |
- |
- |
- |
- |
- |
- |
|
Loss for the year |
- |
- |
- |
(364) |
- |
(364) |
|
Currency translation differences |
- |
- |
- |
- |
- |
- |
|
Total recognised income and expense |
- |
- |
- |
(364) |
- |
(364) |
|
Share capital issued |
193 |
7,021 |
- |
- |
- |
7,214 |
|
Cost of share issue |
- |
(382) |
- |
- |
- |
(382) |
|
Share based payments |
- |
- |
167 |
- |
- |
167 |
|
As at 31 August 2007 |
193 |
6,639 |
167 |
(364) |
- |
6,635 |
|
Loss for the year |
- |
- |
- |
(552) |
- |
(552) |
|
Currency translation differences |
- |
- |
- |
- |
494 |
494 |
|
Total recognised income and expense |
- |
- |
- |
(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 |
|
Company |
||||||
|
As at 09 August 2006 |
- |
- |
- |
- |
- |
- |
|
Loss for the year |
- |
- |
- |
(360) |
- |
(360) |
|
Currency translation differences |
- |
- |
- |
- |
- |
- |
|
Total recognised income and expense |
- |
- |
- |
(360) |
- |
(360) |
|
Share capital issued |
193 |
7,021 |
- |
- |
- |
7,214 |
|
Cost of share issue |
- |
(382) |
- |
- |
- |
(382) |
|
Share based payments |
- |
- |
167 |
- |
- |
167 |
|
As at 31 August 2007 |
193 |
6,639 |
167 |
(360) |
- |
6,639 |
|
Loss for the year |
- |
- |
- |
(1,210) |
- |
(1,210) |
|
Currency translation differences |
- |
- |
- |
- |
- |
- |
|
Total recognised income and expense |
- |
- |
- |
(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 |
NOTES TO THE FINANCIAL STATEMENTS FOR THE PERIOD ENDED 31 DECEMBER 2008
|
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 1985. 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 2008 were authorised for issue by the Board on 27 April 2009 and the balance sheets signed on the Board's behalf by Mr. David Lenigas and Mr. Donald Strang |
|
|
The above financial information comprises non-statutory accounts within the meaning of section 240 of the Companies Act 1985. The financial information for the year ended 31 December 2008 has been extracted from published accounts for the period ended December 2008 that will be delivered to the Registrar of Companies and on which the report of the auditors was unqualified and did not contain statements under s237 (2) or (3) of the Companies Act 1985. |
|
|
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 1985. 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 1 First time Adoption of International Financial Reporting Standards and Consolidated and Separate Financial Statements (1 January 2009) |
|
|
IFRS 2 Amendment to IFRS 2 - Vesting Conditions and Cancellations (1 January 2009) |
|
|
IFRS 3 Business Combinations - revised January 2008 (1 July 2009) |
|
|
IFRS 8 Operating Segments (1 January 2009) |
|
|
IAS 1 Presentation of Financial Statements - revised September 2007 (1 January 2009) |
|
|
IAS 23 Borrowing Costs - revised March 2007 (1 January 2009) |
|
|
IAS 27 Consolidated and Separate Financial Statements - revised January 2008 (1 July 2009) |
|
|
IAS 32 Financial Instruments: Disclosure and Presentation and IAS 1 Presentation of Financial Statements (1 January 2009) |
|
|
Improvements to IFRSs - May 2008 (1 January 2009) |
|
|
IAS 39 Financial Instruments: Recognition and Measurement (1 January 2009) |
|
|
International Financial Reporting Interpretations Committee (IFRIC) |
|
|
IFRIC 13 Customer Loyalty Programmes (1 July 2008) |
|
|
IFRIC 15 Agreements for the construction of real estate (1 January 2009) |
|
|
IFRIC 16 Hedges of a net investment in a foreign operation (1 October 2008) |
|
|
The amendment to IFRS 2 restricts the definition of vesting conditions to include only service conditions (requiring a specified period of service to be completed) and performance conditions (requiring the other party to achieve a personal goal or contribute to achieving a corporate target). All other features are not vesting conditions, and whereas a failure to achieve such a condition was previously regarded as a forfeiture (giving rise to a reversal of amounts previously charged to profit) it must be reflected in the grant date fair value of the award and treated as a cancellation, which results in either an acceleration of the expected charge, or a continuation over the remaining vesting period, depending on whether the condition is under the control of the entity or counterparty. The amendment is mandatory for periods beginning on or after 1 January 2009 and the Group is currently assessing its impact on the financial statements, although it is not expected to be material. |
|
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 |
Business combinations |
|
The acquisition of subsidiaries in a business combination is accounted for using the purchase method. The cost of the acquisition is measured at the aggregate of the fair values, at the date of exchange, of assets given, liabilities incurred or assumed, and equity instruments issued by the Group in exchange for control of the acquiree, plus any costs directly attributable to the business combination. The acquiree's identifiable assets, liabilities and contingent liabilities that meet the conditions for recognition under IFRS 3 are recognised at their fair value at the acquisition date, except for non-current assets (or disposal groups) that are classified as held for sale in accordance with IFRS 5 'Non Current Assets Held for Sale and Discontinued Operations', which are recognised and measured at fair value less costs to sell. |
|
|
Where there is a difference between the Group's interest in the net fair value of the acquiree's identifiable assets, liabilities and contingent liabilities and the cost of the business combination, any excess cost is recognised in the balance sheet as goodwill and any excess net fair value is recognised immediately in the income statement as negative goodwill on acquisition of subsidiary. |
|
|
The interest of minority shareholders in the acquiree is initially measured at the minority's proportion of the net fair value of the assets, liabilities and contingent liabilities recognised. |
|
|
1.06 |
Purchase of a minority interest in a controlled entity |
|
The cost of the purchase of shares is measured at the aggregate of the fair value of assets given at the date of exchange, liabilities incurred or assumed and the fair value of equity instruments issued by the Group in exchange for shares purchased in a controlled entity, plus any costs directly attributable to the transaction. The identifiable assets, liabilities and contingent liabilities of a controlled entity are re-valued to fair value at the date of the acquisition, but only to the extent of the incremental proportion of equity acquired. |
|
|
1.07 |
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. |
|
|
1.08 |
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. |
|
1.08 |
Oil and gas exploration assets and development/producing assets (continued) |
|
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. |
|
|
1.09 |
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. |
|
|
1.10 |
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. |
|
|
1.11 |
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. |
|
|
1.12 |
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. |
|
|
1.13 |
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. |
|
|
1.14 |
Revenue recognition |
|
Turnover 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. |
|
1.15 |
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. Nonߛmonetary 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. |
|
|
1.16 |
Operating leases |
|
The costs of all operating leases are charged against operating profit on a straightߛline 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. |
|
|
1.17 |
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. |
|
|
1.18 |
Finance costs |
|
Borrowing costs are recognised as an expense when incurred |
|
|
1.19 |
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. |
|
1.20 |
Dividends |
|
Dividends are reported as a movement in equity in the period in which they are approved by the shareholders. |
|
|
1.21 |
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. |
|
|
1.22 |
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 cashߛgenerating unit to which the asset belongs is determined. |
|
|
The recoverable amount of an asset or a cashߛgenerating 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 cashߛgenerating unit. This present value is discounted using a preߛtax 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 cashߛgenerating units, or groups of cashߛgenerating 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 cashߛgenerating 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 cashߛgenerating 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. |
|
|
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 |
|
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. |
|
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. |
|
2 |
Turnover and segmental analysis |
||||
|
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) |
|
|
Period 9 August 2006 to 31 August 2007 |
|||||
|
Operating loss by geographical area |
|||||
|
Revenue |
- |
- |
- |
- |
|
|
Operating loss |
(419) |
(4) |
- |
(423) |
|
|
Finance revenue |
59 |
- |
- |
59 |
|
|
Loss before taxation |
(360) |
(4) |
- |
(364) |
|
|
Other information |
|||||
|
Capital additions |
1 |
745 |
- |
746 |
|
|
Segment assets |
1 |
745 |
- |
746 |
|
|
Financial assets |
324 |
- |
- |
324 |
|
|
Cash |
5,753 |
- |
- |
5,753 |
|
|
Consolidated total assets |
6,078 |
745 |
- |
6,823 |
|
|
Segment liabilities |
- |
- |
- |
- |
|
|
Trade and other payables |
(188) |
- |
- |
(188) |
|
|
Consolidated total liabilities |
(188) |
- |
- |
(188) |
|
|
3 |
Operating loss |
2008 |
2007 |
|
|
£ 000's |
£ 000's |
|||
|
Operating loss is arrived at after charging: |
||||
|
Auditors' remuneration - audit |
25 |
8 |
||
|
Auditors' remuneration - non audit services |
- |
- |
||
|
Directors' emoluments - fees and salaries |
54 |
160 |
||
|
Directors' emoluments - share based payments and options |
435 |
167 |
||
|
Depreciation |
119 |
- |
||
|
Amortisation |
18 |
- |
||
|
Auditors' remuneration for non-audit services provided during the period amounted to nil. (2007: nil but £7,500 related to the provision of an accountant's report for the purpose of the Company's AIM admission document and was charged to the share premium reserve, as part of share issue expenses). |
||||
|
4 |
Employee information |
2008 |
2007 |
|
|
Staff costs comprised: |
£ 000's |
£ 000's |
||
|
Wages and salaries |
285 |
- |
||
|
Social security contributions |
71 |
- |
||
|
Total staff costs |
356 |
- |
||
|
The average number of employees on a full time equivalent basis during the year was as follows: |
||||
|
Number |
Number |
|||
|
Administration |
4 |
- |
||
|
Operations |
11 |
- |
||
|
Total |
15 |
- |
||
|
5 |
Taxation |
2008 |
2007 |
|
|
Analysis of charge in period |
£ 000's |
£ 000's |
||
|
Tax on ordinary activities |
- |
- |
||
|
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 |
(552) |
(364) |
||
|
Standard rate of corporation tax in the UK |
28.5% |
30% |
||
|
|
||||
|
Loss on ordinary activities multiplied by the standard rate of corporation tax |
(157) |
(109) |
||
|
Effects of: |
||||
|
Non deductible expenses |
- |
- |
||
|
Future tax benefit not brought to account |
157 |
109 |
||
|
Current tax charge for period |
- |
- |
||
|
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 £960,000 of tax losses yet to be utilised by a subsidiary company in Spain. The Spanish tax rate applicable is currently 35%. |
||||
|
6 |
Dividends |
||||||
|
No dividends were paid or proposed by the Directors (2007: nil). |
|||||||
|
7 |
Directors' emoluments |
||||||
|
2008 |
2007 |
||||||
|
£ 000's |
£ 000's |
||||||
|
Directors' remuneration |
489 |
327 |
|||||
|
|
Directors Fees |
Consultancy Fees |
Share based payments |
Total |
|||
|
2008 |
£ 000's |
£ 000's |
£ 000's |
£ 000's |
|||
|
Executive Directors |
|||||||
|
David Lenigas |
16 |
- |
- |
16 |
|||
|
Jeremy Edelman |
16 |
- |
76 |
92 |
|||
|
Donald Strang |
16 |
- |
312 |
328 |
|||
|
Fraser Pritchard (#) |
6 |
- |
47 |
53 |
|||
|
|
54 |
- |
435 |
489 |
|||
|
2007 |
|||||||
|
Executive Directors |
|||||||
|
David Lenigas |
13 |
41 |
83 |
137 |
|||
|
Jeremy Edelman |
12 |
41 |
42 |
95 |
|||
|
Donald Strang |
12 |
41 |
42 |
95 |
|||
|
|
37 |
123 |
167 |
327 |
|||
|
No pension benefits are provided for any Director. (#) Fraser Pritchard was appointed on 2 July 2008. During the period a total of £411,000 of consultancy fees paid to directors (as detailed in Note 23) 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: |
|||||||
|
2008 |
2007 |
||||||
|
Net loss after taxation (£000's) |
(552) |
(364) |
|||||
|
Weighted average number of ordinary shares used in calculating basic loss per share (millions) |
472.8 |
251.9 |
|||||
|
Weighted average number of ordinary shares used in calculating diluted loss per share (millions) |
533.4 |
259.2 |
|||||
|
Basic loss per share (expressed in pence) |
(0.12) |
(0.14) |
|||||
|
Diluted loss per share (expressed in pence) |
(0.12) |
(0.14) |
|||||
|
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. |
|||||||
|
9 |
Finance revenue |
2008 |
2007 |
|
£ 000's |
£ 000's |
||
|
Bank interest receivable |
153 |
59 |
|
|
10 |
Intangible assets |
2008 |
|
|
Group |
£ 000's |
||
|
Cost |
|||
|
As at 1 September 2007 |
745 |
||
|
Additions |
6,806 |
||
|
As at 31 December 2008 |
7,551 |
||
|
Amortisation |
|||
|
As at 1 September 2007 |
- |
||
|
Amortisation |
18 |
||
|
As at 31 December 2008 |
18 |
||
|
Net book value |
|||
|
As at 31 December 2008 |
7,533 |
||
|
As at 31 August 2007 |
745 |
||
|
2008 |
2007 |
||
|
£ 000's |
£ 000's |
||
|
The net book value is analysed as follows: |
|||
|
Oil and gas properties |
3,583 |
- |
|
|
Deferred exploration expenditure |
3,029 |
745 |
|
|
Decommissioning costs |
921 |
- |
|
|
7,533 |
745 |
||
|
Impairment review |
|||
|
At 31 December 2008, the Directors have carried out an impairment review and confirmed that no provision is currently required. |
|||
|
11 |
Tangible assets |
2008 |
|
|
Group |
£ 000's |
||
|
Cost |
|||
|
As at 1 September 2007 |
1 |
||
|
Additions |
598 |
||
|
Disposals |
(1) |
||
|
As at 31 December 2008 |
598 |
||
|
Depreciation |
|||
|
As at 1 September 2007 |
- |
||
|
Depreciation |
119 |
||
|
Eliminated on disposal |
(1) |
||
|
As at 31 December 2008 |
118 |
||
|
11 |
Tangible assets (continued) |
2008 |
||||||
|
Net book value |
£'000 |
|||||||
|
As at 31 December 2008 |
480 |
|||||||
|
As at 31 August 2007 |
1 |
|||||||
|
Company |
||||||||
|
Cost |
||||||||
|
As at 1 September 2007 |
1 |
|||||||
|
Disposals |
(1) |
|||||||
|
As at 31 December 2008 |
- |
|||||||
|
Depreciation |
||||||||
|
As at 1 September 2007 |
- |
|||||||
|
Depreciation |
1 |
|||||||
|
Eliminated on disposal |
(1) |
|||||||
|
As at 31 December 2008 |
- |
|||||||
|
Net book value |
||||||||
|
As at 31 December 2008 |
- |
|||||||
|
As at 31 August 2007 |
1 |
|||||||
|
Impairment review |
||||||||
|
At 31 December 2008, the Directors have carried out an impairment review and confirmed that no provision is currently required. |
||||||||
|
12 |
Interest in associate |
|||||||
|
Group |
£ 000's |
|||||||
|
Cost |
||||||||
|
As at 1 September 2007 |
- |
|||||||
|
Additions |
14,544 |
|||||||
|
Share of associate's loss for the period |
(128) |
|||||||
|
As at 31 December 2008 |
14,416 |
|||||||
|
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 |
14,416 |
14,416 |
||||||
|
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 2008 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 2008 |
Oil exploration and production |
|||
|
13 |
Investment in subsidiaries |
2008 |
||||||||
|
Shares in Group undertaking |
£ 000's |
|||||||||
|
Company |
||||||||||
|
Cost |
||||||||||
|
As at 1 September 2007 |
1 |
|||||||||
|
Additions |
- |
|||||||||
|
As at 31 December 2008 |
1 |
|||||||||
|
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 |
|||||||
|
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 Holdings Ltd acquired 100% of the share capital of Leni Investments Cps Ltd on 4 December 2007. The company was incorporated on 9 March 2007 Leni Gas and Oil Holdings Ltd acquired 100% of the share capital of Leni Investments Byron Ltd on 10 June 2008. The company was incorporated on 10 June 2008. Leni Gas and Oil Holdings Ltd acquired 100% of the share capital of Leni Investments Trinidad Ltd on 12 June 2008. The company was incorporated on 7 March 2007. |
||||||||||
|
14 |
Trade and other receivables |
2008 |
2007 |
|||||||
|
Group |
Company |
Group |
Company |
|||||||
|
£ 000's |
£ 000's |
£ 000's |
£ 000's |
|||||||
|
Current trade and other receivables |
||||||||||
|
Trade receivables |
177 |
- |
- |
- |
||||||
|
VAT receivable |
28 |
28 |
27 |
27 |
||||||
|
Other receivables |
413 |
474 |
- |
- |
||||||
|
Prepayments |
511 |
79 |
297 |
297 |
||||||
|
Total |
1,129 |
581 |
324 |
324 |
||||||
|
Non current trade and other receivables |
||||||||||
|
Loans due from subsidiaries |
- |
20,855 |
- |
748 |
||||||
|
Total |
- |
20,855 |
- |
748 |
||||||
|
The loans due from subsidiaries are interest free and have no fixed repayment date. |
||||||||||
|
15 |
Inventories |
2008 |
2007 |
||||
|
Group |
Company |
Group |
Company |
||||
|
£ 000's |
£ 000's |
£ 000's |
£ 000's |
||||
|
Inventories - Crude Oil |
129 |
- |
- |
- |
|||
|
16 |
Trade and other payables |
2008 |
2007 |
||||
|
Group |
Company |
Group |
Company |
||||
|
£ 000's |
£ 000's |
£ 000's |
£ 000's |
||||
|
Current trade and other payables |
|||||||
|
Trade Payables |
212 |
152 |
- |
- |
|||
|
Accruals |
282 |
25 |
188 |
188 |
|||
|
Total |
494 |
177 |
188 |
188 |
|||
|
17 |
Provisions |
2008 |
2007 |
||||
|
Group |
Company |
Group |
Company |
||||
|
£ 000's |
£ 000's |
£ 000's |
£ 000's |
||||
|
Provision for decommissioning costs |
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. |
|||||||
|
18 |
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 2008 |
608,254,965 |
304 |
|||||
|
18 |
Share capital (continued) |
|||||||||
|
Total share options in issue |
||||||||||
|
During the period, 16.3 million options were issued (2007: 16 million). |
||||||||||
|
As at 31 December 2008 the options in issue were: |
||||||||||
|
Exercise Price |
Expiry Date |
Options in Issue 31 December 2008 |
||||||||
|
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, 103,863,906 warrants were issued (2007: nil) |
||||||||||
|
As at 31 December 2008 the warrants in issue were; |
||||||||||
|
Exercise Price |
Expiry Date |
Warrants in Issue 31 December 2008 |
||||||||
|
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. 200,000 warrants were exercised during the period (2007: nil). |
||||||||||
|
19 |
Share based payment arrangements |
|||||||||
|
Share options |
||||||||||
|
During the period, 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 are granted under the plan for no consideration. Options are 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 £127,000. As per Note 24, the exercise price of the above options was amended to 5p from the original 10p at grant date and the option charge for the period has been calculated on this basis. 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. |
||||||||||
|
19 |
Share based payment arrangements (continued) |
||||||||
|
The following table lists the inputs to the model used for the period ended 31 December 2008: |
|||||||||
|
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 50% has been applied to the value of the options issued to staff. |
|||||||||
|
20 |
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 |
2008 |
2007 |
|||||||
|
£ 000's |
£ 000's |
||||||||
|
Sterling |
430 |
5,753 |
|||||||
|
US Dollars |
1 |
- |
|||||||
|
Euros |
140 |
- |
|||||||
|
571 |
5,753 |
||||||||
|
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 |
(80) |
80 |
(430) |
430 |
|||||
|
US Dollar |
(14) |
14 |
(14) |
14 |
|||||
|
(94) |
94 |
(444) |
444 |
||||||
|
20 |
Financial instruments (continued) |
|||||||
|
Foreign currency risk (continued) |
||||||||
|
Rates of exchange to £1 used in the financial statements were as follows: |
||||||||
|
As at 31 December 2008 |
Average for the relevant consolidated period to 31 December 2008 |
As at 31 August 2007 |
Average for the period to 31 August 2007 |
|||||
|
Euro |
1.0272 |
1.3005 |
1.4760 |
N/A |
||||
|
US Dollar |
1.4479 |
1.7350 |
2.0139 |
N/A |
||||
|
21 |
Commitments |
|||||||
|
As at 31 December 2008, 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. |
||||||||
|
22 |
Business combinations |
|||||||
|
Acquisition of Compania Petrolifera de Sedano S.L. ("Cps") |
||||||||
|
On 12 November 2007, Leni Investments Cps Ltd ("Leni Investments", a subsidiary of Leni Gas and Oil plc) acquired a 100% interest in Cps for a consideration of approximately £590,000. The consideration was settled by the issue of 8 million new ordinary shares in Leni Gas and Oil plc. |
||||||||
|
Cps (100%) (Book Value) |
Fair Value Adjustment (*) |
Fair Value on acquisition |
||||||
|
£ 000's |
£ 000's |
£ 000's |
||||||
|
Non Current Assets |
||||||||
|
Intangible |
336 |
1,720 |
2,056 |
|||||
|
Tangible |
- |
- |
- |
|||||
|
Current Assets |
||||||||
|
Receivables |
91 |
- |
91 |
|||||
|
Cash |
27 |
- |
27 |
|||||
|
Inventories |
62 |
- |
62 |
|||||
|
Total Assets |
516 |
1,720 |
2,236 |
|||||
|
Payables |
1,646 |
- |
1,646 |
|||||
|
Fair value of Net Assets |
590 |
|||||||
|
Consideration for acquisition |
||||||||
|
Issue of 8 million new ordinary shares of Leni Gas and Oil plc with a market value of 7.37p each |
590 |
|||||||
|
Fair value of net assets acquired |
590 |
|||||||
|
Goodwill arising on acquisition |
- |
|||||||
|
22 |
Business combinations (continued) |
|
|
Acquisition of Compania Petrolifera de Sedano S.L. ("Cps") (continued) |
||
|
The cash inflow on acquisition was as follows; |
£ 000's |
|
|
Net cash acquired with subsidiary |
27 |
|
|
Purchase of minority interest of the Ayoluengo oil field by Cps |
||
|
On 11 April 2008, Cps completed the purchase of the remaining 11.25% minority interest in the Ayoluengo oil field for a cash payment consideration of approximately £251,000. |
||
|
23 |
Related party transactions |
|
|
During the period, the Company paid 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 : £160,000 to David Lenigas, £64,000 to Jeremy Edelman, £112,000 to Isona Services Limited, a Company related to Donald Strang. This amount paid was in accordance with the management services agreement dated 9 August 2006, £75,000 to Fraser Pritchard. |
||
|
24 |
Post balance sheet events |
|
|
On 9 January 2009, the Company announced an amendment to options previously issued on 9 June 2008. The exercise price of the options was amended from 10p per share to 5p per share. All other terms remain the same. The effect of this change in exercise price has been reflected in the share based payment charge in the period ended 31 December 2008 (see note 19). |
||
|
25 |
Profit and loss account of the parent company |
|
|
As permitted by section 230 of the Companies Act 1985, 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 £1.210 million (2007: £0.364 million). |
||
Related Shares:
CERP.L