1 Jun 2012 07:00
For Immediate Release
1 June 2012
LENI GAS AND OIL PLC
("LGO" or the "Company")
Annual Report and Accounts 2011 and Notice of Annual General Meeting
Leni Gas and Oil is pleased to announce that the Company's audited Annual Report and Accounts for the year ended 31 December 2011 will be posted to Shareholders today, together with a Notice of Annual General Meeting ("AGM"), and both documents will be available from the Company's website, www.lenigasandoil.co.uk. The AGM will take place on 29 June 2012 at 11.00 am at the offices of Old Park Lane Capital plc, 49 Berkeley Square, London W1J 5AZ
Highlights
OPERATIONS
·; Total production and production revenue rose by over 18% and 51% respectively relative to 2010
·; During the reporting period Spanish production totalled 49,273 bbls oil and 12.2 mmscf gas , 50,472 boe (2010: 34,984 boe) a 44% year on year improvement
·; Beneficial interest production in Gulf of Mexico totalled 7,639 boe (2010: 12,913 boe) and in Trinidad 6,540 bbls oil (2010: 6,707 bbls)
·; A nine well major workover programme was conducted on the Ayoluengo and Hontomin fields in Spain resulting in increased production to a peak over 300 bopd
·; LGO acquired the exclusive rights to acquire the Goudron Field Incremental Production Contract with Petrotrin in south eastern Trinidad
·; A multi-well farm-in agreement was signed with Advance Oil Company Limited to explore and produce the Moruga North field in south central Trinidad
·; LGO signed new petroleum leases with private owners for 1,752 acres of unexplored lands surrounding the Company's producing Icacos Oilfield in south western Trinidad, increasing its net holdings in the Cedros Peninsula by over 300%
·; The Malta Area 4 PSC was extended by 18 months to allow additional seismic to be conducted before drilling of the first exploration well
·; A new 3D seismic survey covering 1,012 square kilometres was acquired in offshore Malta in order to finalise pre-drill prospect identification
·; The ownership and operatorship of various shallow water Gulf Coast properties was transferred to Marlin Energy LLC following the liquidation of Leed Petroleum plc. Associated production was restored quickly
·; Additional development plans were announced for the Eugene Island Field with two sidetracks planned for early 2012.
CORPORATE
·; The Company put in place an Equity Line Facility for up to £5 million with First Columbus and Dutchess Capital
·; LGO raised £1.51 million in new share equity through the issue of 302 million ordinary shares to support ongoing activities and accelerate the redevelopment of the Spanish assets
·; Steve Horton was appointed as a non-executive director of the company, and Fraser Pritchard retired as an executive director
·; Shore Capital and Old Park Lane were appointed as joint brokers to the Company.
FINANCIALS
·; Gross profit of £1.06 million (2010: £0.52 million)
·; Pre-tax group loss of £3.91 million (2010: £10.29 million, mainly attributable to impairment charge of £1.7m on the Spanish asset (2010: £6.9 million impairment on the Gulf of Mexico investment).
TARGETS FOR 2012
·; Following the Board's decision to focus future growth in Trinidad, the completion of the new business initiatives commenced in 2011 are of paramount importance
·; Trinidad assets on which the Company hopes to commence operations in 2012 include the Goudron Field, the Moruga North leases and the new Cedros Peninsular private leases
·; The conclusion of the partial farmout or sale of the Company's Spanish assets is also envisaged as a key step in refocusing the Company on higher leverage opportunities in Trinidad.
NOTES
·; All figures are net LGO unless otherwise stated.
Chairman's Statement
During the year the Board has been focused on establishing the value of the Spanish assets and increasing our longer term exposure to the onshore oil development potential in Trinidad. The new business development activities in Trinidad have seen us successfully add roughly 5200 net acres of exploration and development leases, a six-fold increase, in a range of transactions due to complete in 2012. This marks a turning point in our portfolio development and we expect to be able to report positively on these investments in the years ahead.
In Spain the programme of well recompletions undertaken in 2011 has allowed us to better define the potential for additional primary recovery from Ayoluengo and Hontomin accumulations. The work directly contributed to an increase of over 100% in the daily production from Ayoluengo, however, it also indicated that future significant growth in production depended on further investment in both wells and pressure maintenance, and ultimately in an enhance oil recovery project. To assist in financing this work LGO announced its intention to seek a joint venture partner and to open a dataroom in early 2012. That process has successfully identified several competitive bidders and we hope to conclude a transaction in 2012 despite the turbulent European markets.
Production in Trinidad has remained solid and has funded the extensive new business development effort that has resulted in the Company having access to development projects at Goudron, Moruga North and Beach-Marcelle, in addition to the Icacos oilfield and surrounding undeveloped leases. In the Goudron field the Company estimates that production can be progressively raised from the current level of approximately 50 bopd to approximately 400 bopd within 12 months and with additional infill drilling and pressure maintenance production can be brought up to a level of over 1,800 bopd within 2 to 3 years. This opportunity, especially when taken alongside others the Company has in Trinidad, offers sustained growth in a basin with significant historic production and a cost structure appropriate to a junior oil and gas company.
In the USA, although production was maintained for most of the year, 2011 was marked by an initial period of inactivity as the Eugene Island operator was unable to fund new well recompletion and development work. Following a two month production stoppage the assets, in which LGO holds a 7.25% interest, were sold to Marlin Energy LLC and production was restored. Marlin has announced plans for additional development drilling on the Eugene Island-184 field and that work is expected to be carried out in 2012.
Our joint study agreement with RAG-Sorgenia to evaluate the shale gas potential of the Cantabrian Basin in Spain was terminated without concluding an agreement to explore in any new areas and as a consequence the Company withdraw a number of licence applications in order to focus on the development potential in the existing 556 sq km core area surrounding the producing Ayoluengo oilfield. Shale gas potential undoubtedly exists in the area and is the object of licensing and drilling activity by other companies, so we expect this opportunity to receive further interest in the future.
In Malta, further work by the operator in the offshore frontier Area 4 PSC established the need to a licence extension and the acquisition of additional long-offset 3D seismic data. The Maltese Resource Agency granted a 15 month extension and approval to acquire the additional data prior to drilling. The seismic was acquired in late 2011 and we hope to see the results of the processed data in the second quarter leading to a drilling decision in late 2012. Independently, and consistent with our focus on core onshore field redevelopment projects, LGO has sought potential buyers for our Maltese interests. The area is a prospective one, however, it does not fit well into our portfolio, diverting much needed capital from early production opportunities elsewhere.
The Company has access to the bulk of the Equity Line Facility initialled with First Columbus in October 2011 and we will use that funding sources as necessary to ensure the company is in a sufficiently strong working capital position as it seeks to complete the various strategic transactions which will shape the future growth of the Company.
I would like to thank shareholders and staff for their continued support in a year when capital markets were especially difficult and during which the Company sought to make a fundamental shift in its strategic focus from Spain to Trinidad. I feel confident that 2012 will start to demonstrate the value of that decision.
David Lenigas
Executive Chairman
31 May 2012
Operations Review
Leni Gas and Oil plc has a strategy to identify and acquire projects and businesses within the oil and gas sector that contain a development premium which can be unlocked through a combination of financial, commercial, and technical expertise.
The Company operates a low risk portfolio of production assets in the US Gulf of Mexico, Spain and Trinidad with significant play upside using similar operating approaches to leverage technologies and proven production enhancement techniques. LGO specifically targets near term production with upside exploitation potential and manages its portfolio to ensure all assets have accelerated incremental reserves and production enhancement programs.
A summary of activity in all countries of operation during the reporting period follows:
SPAIN
LGO holds 100% ownership through its wholly owned subsidiary, Compañia Petrolifera de Sedano (CPS), in one production concession, La Lora (which contains the Ayoluengo producing oilfield), and three exploration permits; Basconcillos H, Huermeces and Valderredible, in Northern Spain. The permits are centrally located in the proven Basque-Cantabrian petroleum basin and cover an area of over 550 sq km, with a processing facility designed to handle 10,000 bbls per day at the producing Ayoluengo oilfield. Ayoluengo is the largest onshore oilfield in Spain and has been in continuous production since its discovery by a Chevron subsidiary in the mid-1960's and was granted a 50 year production concession in 1967 which can be renewed for two additional periods of 10 years whilst the field remains in economic production
Following the award of a field-wide environmental permit for Ayoluengo in late 2010 focus in 2011 was on testing the production potential of the field through a well intervention program involving the mobilisation of a 80 tonne drilling rig from Société de Maintenance Petrolière in France and wireline logging and perforating equipment from Schlumberger. This equipment was used, along with the Company owned Cardwell workover rig, to carry out a range of well interventions on eight Ayoluengo wells (Ayo-4, Ayo-5, Ayo-22, Ayo-32, Ayo-36, Ayo-37, Ayo-46 and Ayo-50) and the Hontomin-2 well at the nearby Company operated Hontomin oilfield, between end-April and late-July. Wells were logged with a variety of wireline tools aimed at establishing the presence of unswept oil in existing open zones or in zones currently not on production. Intervals thought to offer production potential were perforated using wireline tools and the wells returned to production.
Well Ayo-50 was reviewed in order to establish if it could be brought on stream as a dedicated gas production well, having previously logged a high pressure gas zone between 1092 - 1097metres in work undertaken in the early 2000's. Due to the anticipated pressures and uncertainties over the integrity of the casing it was decided not to proceed with perforating the gas zone on this occasion pending further engineering studies. Well Ayo-22 was subsequently logged and prepared as a back-up gas production well to supplement gas supplies in the future. During the remainder of 2011 (and to date in 2012) no such provision has been required with the field continuing to be self-sufficient in fuel gas.
A total of 248.5 metres of potentially oil bearing formations were perforated during the 2011 well campaign, 97.9 metres of which were new, previously unopened, zones and the balance were new perforations in existing open zones. Of the total, 95% of the perforations were carried out in the Ayoluengo wells and the balance in the Hontomin-2 well (13.5 metres). With the exception of the gas wells Ayo-22 and Ayo-50, all other wells were recompleted and returned to production at the end of the workover campaign.
Immediately following the intervention at Ayoluengo production exceeded 300 bopd, the highest production rate observed since 2008. Additional issues with wax formation and scale build-up were identified in some wells and programmes to treat these were designed during the 4th quarter 2011 for potential use in 2012 and beyond. Notwithstanding the significant production increase the intervention programme was unable to demonstrate the potential for production to exceed the 400 bopd target set in early 2011, beyond which free cash flow would fund additional capital investment. Consequently it was decided to seek a partner with whom further investment could be shared. Potential partners were invited to make expressions of interest in late 4th quarter and a dataroom was opened on the 4 January 2012. The dataroom was closed in March 2012 and a call for bids resulted in a number of commercial proposals to acquire or farm-in to the Company's Spanish assets.
Pending the completion of a farm-out or sale, a cost reduction exercise was undertaken to streamline the field operations within the new parameters of peak production of 300 bopd. Between the 3rd quarter of 2011 and the 1st quarter of 2012 operating saving equivalent to approximately €42,000 per month were made, a net reduction of 16% in the operating budget of the field. These cost savings have been maintained and further increased in 2012 to ensure the field continues to make a sustainable profit and material contribution to the Company.
In November the Company's Cardwell rig was taken out of service for a period of four weeks for a five-year recertification. This coincided with a breakdown of the Ayo-37 well and resulted in an estimated 8,900 bbls of deferred production.
During the reporting period there were no major accidents or incidents at the field. Despite a more than 100% increase in man-hours through the year with the major workover campaign there were no significant lost-time accidents. Work to improve the environmental standards of the field, especially the production well pads and local well storage tanks, has continued in line with the environmental standards set in the 2010 Environmental Permit. It is anticipated that the well pad upgrade work will be fully completed in 2012.
In May a new sales contract was signed with the Spanish industrial company Saint-Gobain Vicasa SA to lift Ayoluengo crude oil to use as fuel oil in their various factories within Northern Spain. Under the terms of the contract CPS receives a price pegged to Brent and discounted for the fuel oil grade and various impurities. Discussions have been maintained with BP Espana on the contract to lift refinery grade crude oil when quantities are sufficient and in the 3rd quarter 2011 the contract was amended in order to reflect the delay in reaching the anticipated 500 bopd threshold in the original contract signed in late 2010.
In the Huermeces licence, following good initial flow rates from the Hontomin-2 (H-2) well the Company applied for the conversion of the Exploration Licence to a Production Concession. This application was filed with the Ministry in February 2011. The H-2 well was re-entered during the workover campaign however was found to have a "fish" (an obstruction caused by mechanical debris) of unknown provenance located across part of the open perforations. Attempts to mill the fish were unsuccessful and as a result only a small portion of the well could be logged and as a result just 7.5 metres of new perforations were shot, compared to the 40 metres originally planned. Production was restored; however, due to presumed formation damage during the milling operation only limited new production was achieved. It was subsequently decided to suspend production since the cost of operating a single remote well were considered prohibitive. Additional desk-top studies are being undertaken to establish the best means to recover the known reserves from the Hontomin Field.
The Company and Ciudad de la Energia (CIUDEN) have a Joint Venture signed in 2010 under which CIUDEN plans to utilise the Hontomin structure for a commercial trial of carbon dioxide storage. CIUDEN have completed their 3D seismic interpretation and initiated permitting on two new drilling sites on the flanks of the Hontomin field. Discussions on the future use of the H-2 well in combination with the CIUDEN project have been held and it is anticipated that H-2 will be re-entered in 2012 to make changes to the down-hole configuration to facilitate future joint studies.
There has been no work undertaken in the Basconcillos-H licence area where the Tozo gas well is located. This project is dormant pending further studies of potential uses of the gas discovered in Tozo. After conducting studies of the unconventional gas potential in the Cantabrian Basin LGO's joint study agreement with Sorgenia International B.V and Rohöl-Aufsuchungs Aktiengesellschaft announced in November 2010 was terminated. Whilst the parties to the agreement recognised that there was considerable potential for shale gas within the basin and in part beneath the CPS held licences, it was concluded that insufficient immediate potential existed at this time to justify early drilling. As a consequence LGO withdrew various applications for a number of potential new licence areas and will await further regional activity by other operators before determining the best means to commercialise the unconventional gas potential within its assets.
In 2012, the commercial effort undertaken through the dataroom resulted in the receipt of multiple competing bids for participation in the Ayoluengo Field and CPS's wider portfolio. After review the Company decided to sell the entire position in Spain in order to realise a cash profit and re-invest the funds in Trinidad. A preferred bidder was selected and granted exclusivity until the end-May 2012 to agree definitive documentation. At the time of this report discussions were continuing with a view to closing a number of due diligence items during which time exclusivity has not been extended. Several new expressions of interest have been received and despite the poor business climate in Europe at present interest in primary energy production remains strong. The Company continues to feel that a transaction is likely with one of the bidders, however, should a transaction not successfully complete the current production from the Ayoluengo Field is more than sufficient to sustain ongoing operations in Spain for the foreseeable future.
Overall production recorded from the Company's assets in Spain in 2011 totalled 49,273 bbls oil and 12 mmcf gas (50,472 boe) which compares to 34,984 boe in 2010, a 44% increase overall.
US GULF OF MEXICO
LGO retains rights within sixteen blocks in the shallow water US GoM covering leases at West Cameron, South Marsh Island, Eugene Island, Ship Shoal, Grand Isle and Main Pass. The Company currently retains direct working interests in Eugene Island, South Marsh Island and Ship Shoal leases with exercise options in the remainder. The Grand Isle leases are expected to be relinquished in 2012.
Under terms of the 2009 agreement with Byron Energy LLC (Byron), LGO converted its 28.94% interest in Byron 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") lease. Net revenue interests range from 2.50540% to 6.04167%. The Eugene
Island Field, operated firstly by Leed Petroleum plc (LDP) and latterly by Marlin Energy LLC (Marlin) is the only current producing property in which LGO holds a direct interest.
The Eugene Island Field is located 50 miles offshore Louisiana in approximately 80 feet of water, and was operated by LDP on behalf of the joint venture with Byron and LGO. Production in the field comes from Tertiary sands at depths ranging from 12,000 to 15,000 feet. During 2010 production from Eugene Island continued to decline due to natural depletion and the onset of water production from some of the wells.
In late March 2010 LDP notified its partners that it planned to unilaterally shut in production from the Eugene Island Field as it was unable to meet its financial obligations to its major creditors. The field was shut in on the 31 March 2011. In May 2011 LDP sold its entire interest in all its GoM properties to Marlin who assumed operatorship and then successfully restarted production in June 2011.
Although no well recompletion activities were undertaken in 2011 Marlin submitted plans for two sidetracks from well A-2 and a well recompletion on A-8 to be undertaken in early 2012 once a suitable rig was available. Due to various delays and a short rig slot only one well was attempted in early 2012, A-2ST01, which found a thin hydrocarbon pay in the Tex-X2 sandstone, but was not considered commercially viable for production. Further proposals on capital projects to recover the remaining reserves at the Eugene Island Field are expected from the operator in due course.
The Company previously exercised its options in South Marsh Island block 6 and Ship Shoal block 180 which were awarded to Byron independently in April 2010 through Lease Sale 213 and are covered within the Company's Strategic Scouting Agreement with Byron. LGO acquired 20% direct working interests (16.25% net revenue post royalty) in both Ship Shoal block 180 and South Marsh Island block 6 in the shallow offshore US Gulf Coast. Byron conducted seismic and other studies during 2011 and is expected to propose drilling on one of these leases in 2012/2013.
Total net production during 2011 from the Eugene Island production asset was 7,639 boe. The lower production in 2011, relative to 2010 (-42%), representing a combination of continued slow well performance decline and the approximately 60 days of field outage during the sale of LDP's interests to Marlin.
TRINIDAD
In 2011 the Company initiated a substantial new business development effort in Trinidad. After commencing business in Trinidad in January 2008 through the acquisition of the interests of Eastern Petroleum Australia (EPA) which was formally completed as of 1 January 2011, LGO had established a strong business foundation in the country and in order to diversify its European production base the decision was made to expand and enhance the portfolio in Trinidad. Over the course of 2011 the Company increased its interests from 850 net acres to in excess of 6,000 net acres, mostly in producing assets that it is hoped can be operational in 2012.
The Company retains a 50% ownership to the EPA Icacos oilfield, covering approximately 1,900 gross acres, located on the Cedros Peninsula of south western Trinidad, within the East Venezuelan basin. The field is operated by Primera Oil and Gas Limited (Primera) who retain the other 50% interest in the field. Primera Oil and Gas Limited was acquired by Touchstone Exploration Ltd in August 2011 and LGO has been working with the new owners to obtain a new petroleum licence for the field prior to initiating further investment, which it is anticipated can raise production from the existing shallow Upper Cruse horizons.
LGO has also acquired the exclusive subsurface rights to 1,752 acres of private lands held by the Columbia and Perseverance Estates in the Cedros Peninsula around the Icacos field. These leases form the core of LGO's strategy to explore the deeper potential of the Cedros Peninsula which is geologically contiguous with the prolific East Venezuela basin which lies immediately adjacent to the west. A private petroleum licence will be applied for in 2012 and it is anticipated that studies can commence by end 2012 and exploration field operations will be underway in 2013. An airborne gravity survey is considered to offer the most immediate cost effective method of establishing the prospectivity of the Cedros Peninsula, although plans for 2D seismic are also under consideration.
In July LGO announced that it had reach agreement with Advance Oil Company (Trinidad) Limited (AOCL) to farm-in to the various AOCL leases in the Moruga North area of central southern Trinidad. The leases covering 1,223 gross acres lie between the producing East Moruga and Innis, Antilles and Trinity oil fields. The arrangements for the farm-in include LGO re-establishing production from the existing Moruga North wells and drilling three exploration wells and up to six appraisal and development wells during a 3 year earn-in period. LGO is expected to earn a 45% interest in the properties and has been working with AOCL in 2011 and early 2012 to address various legacy lease issues before embarking on the first new well. Plans are in place to spud the first well in 2012 once all the regulatory approvals have been received for the transfer of interest.
Initial production from the existing Moruga North (MN-44 and MN-209) wells, once recompleted, is expected to be 120 bopd (gross) in which LGO will hold an initial 33% interest. Work to complete these wells will be carried out contemporaneously with the drilling planned for 2012. The Moruga area contains oil in the prolific Herrera Formation sandstones and only limited recent exploration has been carried out, offering substantial further potential for producible oil.
In October the Company signed an agreement with Sorgenia Trinidad and Tobago Holdings Limited (Sorgenia) to acquire the outstanding share capital in newly incorporated Trinidadian company Goudron E&P Limited (GEPL). GEPL holds the exclusive
rights to acquire the Incremental Production Service Contract (IPSC) from its current owner Cameron Oil and Gas Limited (Cameron). The IPSC for the Goudron Field was awarded by the Petroleum Company of Trinidad Limited (Petrotrin) in late 2009 and covers a 2,875 gross acre concession in the Eastern Fields area of southern Trinidad.
The Goudron Field was discovered in 1927 and developed by Trinidad Leaseholders Limited and then by Texaco from 1956 to 1986, after which the lease reverted to a predecessor company of Petrotrin. A total of at least 152 wells have been drilled on the field which produces light crude (25 to 55 degree API) from the Goudron Sandstones and deeper Gros Morne (Upper Cruse Formation) at depths from 300 to 3,500 feet. Deeper reservoirs in the Lower Cruse are also known to be present. Export is to the Petrotrin refinery at Point-a-Pierre by pipeline and cumulative historic production totals just less than 5 mmbbls.
LGO believes that with the application of new technology and an increase in investment production in the Goudron Field can be raised substantively over the next few years. Initial work will concentrate on working over existing and dormant wells; up to 50 in total, and then the drilling of up to 30 new infill wells. New sand control techniques and fraccing will both be used to stimulate wells and increase flow rates. The immediate target is to raise production to 400 to 500 bopd in the first 12-18 months. A Competent Persons Report has been commissioned for release in the 3rd quarter 2012. Current reserves estimates from Sorgenia indicate proven plus probable reserves of approximately 8 mmbbls; but with very considerable longer term upside.
At the end of the reporting period the transfer of the IPSC from Cameron to GEPL was awaited. At the time of this report field operations had been initiated with work-overs on three to five wells being agreed and a rig mobilised to commence that work.
In March 2012 LGO agreed a heads of terms on a potential farm-out of the Goudron interest to Range Resources Limited (Range), in which Range would acquire an initial 30% interest in GEPL and hold an option to acquire a second 20% tranche within 12 months. In return LGO would receive an option, once Range had exercised their second tranche in Goudron, to acquire a 15% interest in the Range operated Beach-Marcelle IPSC.
Taken together the Company's new business activities in 2011 across Trinidad from Icacos, Cedros, Moruga, Goudron and Beech-Marcelle represent a substantial realisation of the increased focus that the Board agreed to direct to Trinidad in order to provide increased options for growth within the Company.
Overall production in Trinidad during 2011 was limited to LGO's 50% share of the Icacos Field where a total of 6,540 bbls net to the Company's interest were produced, down slightly on 2010 (-2%) due to slightly higher well downtime. Icacos production at the present level is expected to be maintained in 2012, although agreement with Touchstone to carry out workovers may see production levels rise over time. Production from both Moruga North and Goudron are anticipated to commence in the second half of 2012.
MALTA
LGO retains a 10% interest in Area 4 (comprising Blocks 4, 5, 6 and 7) of Southern Offshore Malta, operated by Mediterranean Oil & Gas plc (MOG) who hold the balance of the interest. The Area is governed under a Production Sharing Contract (PSC) with the Maltese Ministry of Natural Resources.
An extension was granted in late May under the PSC by the Maltese Government for a period of 18 months. This extension was granted in return for the payment by the joint owners of a US$300,000 extension bonus and the revision of several other PSC terms. Drilling is now to occur in the PSC area prior to 18 January 2013 and an additional 1,000 sq km 3D seismic programme was to be acquired in 2011 to complete the pre-drill technical evaluation.
The required seismic data was acquired between the 18th November and the 14th December 2011 using the Fugro-Geoteam PTY Limited owned vessel M/V Geo Barents. In total 1,012 square kilometres of 3D data were acquired using a long-offset source and receiver configuration to better image the deeper Cretaceous structures within the Melita-Medina Graben.
The most mature prospect, located in in Block 7, Tarxien, is located close to the Libyan border and is covered by the newly acquired seismic. The combination of a shallower Lower Eocene reservoir and a deeper Upper Cretaceous reservoir at this location offers the best potential economics on a well to test the prospectivity of the PSC.
The seismic processing was commenced in January 2012 and is expected to be interpreted in the 3rd quarter. A well to a minimum depth of 2500 metres is required to be drilled by early 2013, and therefore the Maltese Authorities have been requested to offer a short further extension in order to facilitate well planning and a potential farm-out. A decision is expected in June 2012. LGO considers the Maltese assets valuable, but non-core to its overall mission of developing existing reserves with associated upside, and has made its 10% interest available for sale. Several expressions of interest have been evaluated although at the time of this report no final decision had been reached.
The past year has been a challenging one requiring both dedication and hard work from the staff in London, Spain and Trinidad. A great deal has been accomplished and this phase will hopefully be successfully completed in 2012, allowing the Company to achieve renewed growth and shareholder value.
Neil Ritson
Chief Executive Officer
31 May 2012
Competent Person's statement:
The information contained in this document has been reviewed and approved by Neil Ritson, Executive Director for Leni Gas & Oil Plc. Mr Ritson is a member of the Society of Petroleum Engineers and Fellow of the Geological Society, an Active Member of the American Association of Petroleum Geologists and has over 35 years relevant experience in the oil industry.
Finance Review
Economic environment
The performance of the Company will be influenced by global economic conditions, and in particular, the conditions prevailing in the United Kingdom, Spain, USA and Trinidad. The economies in these regions have all been subject to recessionary pressures during the period, with the global economy experiencing continued difficulties during 2011. The Company continues to monitor all of these markets particularly in relation to the Company's future project and operational development plans.
Results for the period
2011 continued to mark the turning point in the evolution of Leni Gas and Oil plc, highlighted by the encouraging production arising from further developing our Spanish 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 £1.06 million (2010: £0.52 million) and an operating loss after tax of £4.1 million (2010: £10.29 million) for the period ended 31 December 2011 mainly attributable to an impairment charge of £1.7 million (2010: £6.9 million) relating to the provision for write-down of the Company's investments in Spain (2010, impairment charge for write-down of Company's investment in GoM).
Revenue in the period of £3.42 million (2010: £2.26 million) arose from oil and gas sales from operations.
Cash flow
Cash outflow from operating activities after movements in working capital amounted to £0.57 million (2010: outflow £1.20 million). Net cash inflow from financing activities was £2.42 million (2010: £6.99 million). Net cash outflow from investing activities was £4.62 million (2010: £1.96 million) of which £3.71 million (2010: £1.98 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 2011 was £1.06 million. (2010: £3.85 million).
Key performance indicators
The current business of the Company continues to be fundamentally in a development and initial production stage with the focus on the successful delivery of investment to enable the Company to progress to substantial oil and gas sales and a larger operational business. The Company has devised strategies to monetise the majority of its oil and gas assets primarily by means of various production enhancement, development expansion and commercial consolidation programs as outlined in the Operations Review. The Board and management are incentivised to deliver shareholder value in line with these plans. The Company intends to provide detailed analysis and comparison of production; cash flows from operations; operating costs per boe; and realised oil and gas prices per barrel and mscf in future Annual reports.
Outlook
Having acquired various oil and gas assets and securing the team to expedite the various implementation plans, LGO's financial future is very promising. With the prospect of generating significantly increased operational cashflow in the foreseeable future, the real monetisation of our assets and delivery of their potential is commencing.
GLOSSARY & NOTES
2D = two-dimensional
3D = three-dimensional
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
CO2 = carbon dioxide
EOR = enhanced oil recovery
GoM = US Gulf of Mexico
m = thousand
mm = million
mscf = thousand standard cubic feet of gas
mmscf = million standard cubic feet of gas
mmscfd = million standard cubic feet of gas per day
PSC = Production Sharing Contract
sq km = square kilometres
All figures are net LGO unless otherwise stated
All reserves and resources definitions used are per the Society of Petroleum Engineers' Petroleum Resources Management System.
Financial Statements
GROUP STATEMENT OF COMPREHENSIVE INCOMEFOR THE YEAR ENDED 31 DECEMBER 2011
Year ended | Year ended | ||
31 December 2011 | 31 December 2010 | ||
Note | £ 000's | £ 000's | |
Revenue | 2 | 3,417 | 2,264 |
Cost of sales | (2,356) | (1,741) | |
Gross profit | 1,061 | 523 | |
Administrative expenses | 3 | (2,279) | (1,473) |
Amortisation and depreciation | 3 | (565) | (1,843) |
Share based payments | 20 | (421) | (610) |
(Loss) from operations | (2,204) | (3,403) | |
Impairment charge | 12 | (1,685) | (6,904) |
Finance charges | 17 | (30) | - |
Finance revenue | 9 | 8 | 15 |
(Loss) before taxation | (3,911) | (10,292) | |
Income tax expense | 5 | (155) | 5 |
(Loss) for the year attributable to equity holders of the parent | (4,066) | (10,287) | |
Other comprehensive income | |||
Exchange differences on translation of foreign operations | (196) | (113) | |
Other comprehensive income for the year net of taxation | (196) | (113) | |
Total comprehensive income for the year attributable to equity holders of the parent | (4,262) | (10,400) | |
Loss per share (pence) | |||
Basic | 8 | (0.43) | (1.51) |
Diluted | 8 | (0.43) | (1.51) |
All of the operations are considered to be continuing. |
GROUP STATEMENT OF FINANCIAL POSITIONAS AT 31 DECEMBER 2011
As at 31 December 2011 | As at 31 December 2010 | ||
Note | £ 000's | £ 000's | |
Assets | |||
Non-current assets | |||
Property, plant and equipment | 11 | 244 | 303 |
Intangible assets | 10 | 16,876 | 15,125 |
Goodwill | 10 | 3,083 | - |
Total non-current assets | 20,203 | 15,428 | |
Current assets | |||
Inventories | 15 | 233 | 96 |
Trade and other receivables | 14 | 1,162 | 446 |
Cash and cash equivalents | 1,056 | 3,852 | |
Total current assets | 2,451 | 4,394 | |
Total assets | 22,654 | 19,822 | |
Liabilities | |||
Current liabilities | |||
Trade and other payables | 16 | (2,155) | (555) |
Deferred consideration | 16 | (737) | - |
Taxation | 16 | (57) | - |
Total current liabilities | (2,949) | (555) | |
Non-current liabilities | |||
Deferred consideration | 16 | (1,850) | - |
Borrowings | 17 | (718) | - |
Provisions | 18 | (799) | (817) |
Total non-current liabilities | (3,367) | (817) | |
Total liabilities | (6,316) | (1,372) | |
Net assets | 16,338 | 18,450 | |
Shareholders' equity | |||
Called-up share capital | 19 | 630 | 460 |
Share premium | 31,751 | 30,192 | |
Share based payments reserve | 20 | 1,251 | 830 |
Retained earnings | (17,328) | (13,262) | |
Foreign exchange reserve | 34 | 230 | |
Total equity attributable to equity holders of the parent | 16,338 | 18,450 |
COMPANY STATEMENT OF FINANCIAL POSITIONAS AT 31 DECEMBER 2011
As at 31 December 2011 | As at 31 December 2010 | ||
Note | £ 000's | £ 000's | |
Assets | |||
Non-current assets | |||
Property, plant and equipment | 11 | 7 | - |
Investment in subsidiaries | 13 | 3,085 | 2 |
Trade and other receivables | 14 | 24,467 | 20,824 |
Total non-current assets | 27,559 | 20,826 | |
Current assets | |||
Trade and other receivables | 14 | 3,105 | 2,007 |
Cash and cash equivalents | 484 | 3,744 | |
Total current assets | 3,589 | 5,751 | |
Total assets | 31,148 | 26,577 | |
Liabilities | |||
Current liabilities | |||
Trade and other payables | 16 | (706) | (297) |
Deferred consideration | 16 | (737) | - |
Total liabilities | (1,443) | (297) | |
Non-current liabilities | |||
Deferred consideration | 16 | (1,850) | - |
Borrowings | 17 | (718) | - |
Total non-current liabilities | (2,568) | - | |
Total liabilities | (4,011) | (297) | |
Net assets | 27,137 | 26,280 | |
Shareholders' equity | |||
Called-up share capital | 19 | 630 | 460 |
Share premium | 31,751 | 30,192 | |
Share based payments reserve | 20 | 1,251 | 830 |
Retained earnings | 25 | (6,495) | (5,202) |
Total equity attributable to equity holders of the parent | 27,137 | 26,280 |
GROUP STATEMENT OF CASH FLOWSFOR THE YEAR ENDED 31 DECEMBER 2011
Year ended | Year ended | |
31 December 2011 | 31 December 2010 | |
£ 000's | £ 000's | |
Cash outflow from operating activities | ||
Operating (loss) | (2,204) | (3,403) |
(Increase)/decrease in trade and other receivables | (716) | 476 |
Increase /(decrease)in trade and other payables | 1,600 | (803) |
(Increase)/decrease in inventories | (137) | 72 |
Depreciation | 69 | 66 |
Amortisation | 496 | 1,777 |
Share based payments | 421 | 610 |
Income tax (paid)/received | (98) | 6 |
Net cash (outflow) from operating activities | (569) | (1,199) |
Cash flows from investing activities | ||
Interest received | 8 | 15 |
Payments to acquire subsidiaries | (617) | - |
Payments to acquire intangible assets | (3,997) | (1,978) |
Payments to acquire tangible assets | (15) | - |
Net cash outflow from investing activities | (4,621) | (1,963) |
Cash flows from financing activities | ||
Issue of ordinary share capital | 1,812 | 7,801 |
Share issue costs | (83) | (359) |
Proceeds/(repayments) of borrowings | 688 | (453) |
Net cash inflow from financing activities | 2,417 | 6,989 |
Net (decrease)/increase in cash and cash equivalents | (2,773) | 3,827 |
Foreign exchange differences on translation | (23) | (205) |
Cash and cash equivalents at beginning of period | 3,852 | 230 |
Cash and cash equivalents at end of period | 1,056 | 3,852 |
COMPANY STATEMENT OF CASH FLOWSFOR THE YEAR ENDED 31 DECEMBER 2011
Year ended | Year ended | |
31 December 2011 | 31 December 2010 | |
£ 000's | £ 000's | |
Cash outflow from operating activities | ||
Operating (loss) | (1,267) | (1,316) |
(Increase) in trade and other receivables | (1,098) | (959) |
Increase/(decrease) in trade and other payables | 409 | (94) |
Share based payments expensed | 421 | 610 |
Depreciation | 2 | - |
Other non-cash adjustments | 1 | - |
Income tax repayment | - | 6 |
Net cash outflow from operating activities | (1,532) | (1,753) |
Cash flows from investing activities | ||
Interest received | 4 | 15 |
Loans granted to subsidiaries | (3,523) | (1,533) |
Payments to acquire subsidiaries | (617) | - |
Payments to acquire tangible assets | (9) | - |
Net cash outflow from investing activities | (4,145) | (1,518) |
Cash flows from financing activities | ||
Issue of ordinary share capital | 1,812 | 7,801 |
Share issue costs | (83) | (359) |
Proceeds/(repayments) of borrowings | 688 | (453) |
Net cash inflow from financing activities | 2,417 | 6,989 |
Net (decrease)/increase in cash and cash equivalents | (3,260) | 3,718 |
Cash and cash equivalents at beginning of period | 3,744 | 26 |
Cash and cash equivalents at end of period | 484 | 3,744 |
STATEMENT OF CHANGES IN EQUITYFOR THE YEAR ENDED 31 DECEMBER 2011
Called up share capital | Share premium reserve | Share based payments reserve | Retained earnings | Foreign exchange reserve | Total Equity | |
£ 000's | £ 000's | £ 000's | £ 000's | £ 000's | £ 000's | |
Group | ||||||
As at 31 December 2009 | 304 | 22,663 | 463 | (2,975) | 343 | 20,798 |
Loss for the year | - | - | - | (10,287) | - | (10,287) |
Currency translation differences | - | - | - | - | (113) | (113) |
Total comprehensive income | - | - | - | (10,287) | (113) | (10,400) |
Share capital issued | 156 | 7,888 | - | - | - | 8,044 |
Cost of share issue | - | (359) | - | - | - | (359) |
Share based payments | - | - | 367 | - | - | 367 |
Total contributions by and distributions to owners of the Company | 156 | 7,529 | 367 | - | - | 8,052 |
As at 31 December 2010 | 460 | 30,192 | 830 | (13,262) | 230 | 18,450 |
Loss for the year | - | - | - | (4,066) | - | (4,066) |
Currency translation differences | - | - | - | - | (196) | (196) |
Total comprehensive income | - | - | - | (4,066) | (196) | (4,262) |
Share capital issued | 170 | 1,642 | - | - | - | 1,812 |
Cost of share issue | - | (83) | - | - | - | (83) |
Share based payments | - | - | 421 | - | - | 421 |
Total contributions by and distributions to owners of the Company | 170 | 1,559 | 421 | - | - | 2,150 |
As at 31 December 2011 | 630 | 31,751 | 1,251 | (17,328) | 34 | 16,338 |
Company | ||||||
As at 31 December 2009 | 304 | 22,663 | 463 | (3,907) | - | 19,523 |
Loss for the year | - | - | - | (1,295) | - | (1,295) |
Total comprehensive income | - | - | - | (1,295) | - | (1,295) |
Share capital issued | 156 | 7,888 | - | - | - | 8,044 |
Cost of share issue | - | (359) | - | - | - | (359) |
Share based payments | - | - | 367 | - | - | 367 |
Total contributions by and distributions to owners of the Company | 156 | 7,529 | 367 | - | - | 8,052 |
As at 31 December 2010 | 460 | 30,192 | 830 | (5,202) | - | 26,280 |
Loss for the year | - | - | - | (1,293) | - | (1,293) |
Total comprehensive income | - | - | - | (1,293) | - | (1,293) |
Share capital issued | 170 | 1,642 | - | - | - | 1,812 |
Cost of share issue | - | (83) | - | - | - | (83) |
Share based payments | - | - | 421 | - | - | 421 |
Total contributions by and distributions to owners of the Company | 170 | 1,559 | 421 | - | - | 2,150 |
As at 31 December 2011 | 630 | 31,751 | 1,251 | (6,495) | - | 27,137 |
NOTES TO THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2011
1 | Summary of significant accounting policies | |
1.01 | General information and authorisation of financial statements | |
Leni Gas and Oil plc is a public limited company registered in the United Kingdom under the Companies Act 2006. The address of its registered office is Suite 3B, Princes House, 38 Jermyn Street, London, SW1Y 6DN. 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 2011 were authorised for issue by the Board on 24 May 2012 and the balance sheets signed on the Board's behalf by Mr. David Lenigas and Mr. Neil Ritson | ||
1.02 | Statement of compliance with IFRS | |
The Group's financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS). The Company's financial statements have been prepared in accordance with IFRS as adopted by the European Union and as applied in accordance with the provisions of the Companies Act 2006. The principal accounting policies adopted by the Group and Company are set out below.
Future changes in accounting policies
IASB (International Accounting Standards Board) and IFRIC (International Financial Reporting Interpretations Committee) have issued the following standards and interpretations with an effective date after the date of these financial statements: | ||
New/Revised International Financial Reporting Standards (IAS/IFRS) | Effective date (accounting periods commencing on or after)
| |
IAS 12 Income Taxes - Limited scope amendment (recovery of underlying assets) (December 2010) | 1 January 2012 | |
IAS 27 Consolidated and Separate Financial Statements - Reissued as IAS 27 Separate Financial Statements (as amended in May 2011) | 1 January 2013 | |
IAS 28 Investments in Associates - Reissued as IAS 28 Investments in Associates and Joint Ventures (as amended in May 2011) | 1 January 2013 | |
IFRS 7 Financial Instruments: Disclosures - Amendments enhancing disclosures about transfers of financial assets (October 2010) | 1 July 2011 | |
IFRS 9 Financial Instruments - Classification and Measurement | 1 January 2013 | |
IFRS 10 Consolidated Financial Statements* | 1 January 2013 | |
IFRS 11 Joint Arrangements* | 1 January 2013 | |
IFRS 12 Disclosure of Interests in Other Entities* | 1 January 2013 | |
IFRS 13 Fair Value Measurement* | 1 January 2013 | |
* Original issue May 2011 | ||
1.03 | Basis of preparation | |
The consolidated financial statements have been prepared on the historical cost basis, except for the measurement to fair value of assets and financial instruments as described in the accounting policies below, and on a going concern basis.
| ||
The financial report is presented in Pound Sterling (£) and all values are rounded to the nearest thousand pounds (£'000) unless otherwise stated. | ||
1.04 | Basis of consolidation | |
The consolidated financial information incorporates the results of the Company and its subsidiaries ("the Group") using the purchase method. In the consolidated balance sheet, the acquiree's identifiable assets, liabilities are initially recognised at their fair values at the acquisition date. The results of acquired operations are included in the consolidated income statement from the date on which control is obtained. Inter-company transactions and balances between Group companies are eliminated in full. | ||
1.05 | Goodwill and intangible assets | |
Intangible assets are recorded at cost less eventual amortisation and provision for impairment in value. Goodwill on consolidation is capitalised and shown within non-current assets. Positive goodwill is subject to an annual impairment review, and negative goodwill is immediately written-off to the income statement when it arises. | ||
1.06 | Oil and gas exploration assets and development/producing assets |
The Group applies the successful efforts method of accounting for oil and gas assets, having regard to the requirements of IFRS 6 'Exploration for and Evaluation of Mineral Resources'.
| |
All licence acquisition, exploration and evaluation costs are initially capitalised as intangible fixed assets in cost centres by field or by exploration area, as appropriate, pending determination of commerciality of the relevant property. Directly attributable administration costs are capitalised insofar as they relate to specific exploration activities, as are finance costs to the extent they are directly attributable to financing development projects. Pre-licence costs and general exploration costs not specific to any particular licence or prospect are expensed as incurred.
| |
If prospects are deemed to be impaired ('unsuccessful') on completion of the evaluation, the associated costs are charged to the income statement. If the field is determined to be commercially viable, the attributable costs are transferred to development/production assets within property, plant and equipment in single field cost centres.
| |
Subsequent expenditure is capitalised only where it either enhances the economic benefits of the development/producing asset or replaces part of the existing development/producing asset.
| |
Net proceeds from any disposal of an exploration asset are initially credited against the previously capitalised costs. Any surplus proceeds are credited to the income statement. Net proceeds from any disposal of development/producing assets are credited against the previously capitalised cost. A gain or loss on disposal of a development/producing asset is recognised in the income statement to the extent that the net proceeds exceed or are less than the appropriate portion of the net capitalised costs of the asset.
| |
1.07 | Commercial reserves |
Commercial reserves are proven and probable oil and gas reserves, which are defined as the estimated quantities of crude oil, natural gas and natural gas liquids which geological, geophysical and engineering data demonstrate with a specified degree of certainty to be recoverable in future years from known reservoirs and which are considered commercially producible. There should be a 50 per cent statistical probability that the actual quantity of recoverable reserves will be more than the amount estimated as a proven and probable reserves and a 50 per cent statistical probability that it will be less. | |
1.08 | Depletion and amortisation |
All expenditure carried within each field is amortised from the commencement of production on a unit of production basis, which is the ratio of oil and gas production in the period to the estimated quantities of commercial reserves at the end of the period plus the production in the period, generally on a field by field basis. In certain circumstances, fields within a single development area may be combined for depletion purposes. Costs used in the unit of production calculation comprise the net book value of capitalised costs plus the estimated future field development costs necessary to bring the reserves into production. Changes in the estimates of commercial reserves or future field development costs are dealt with prospectively. | |
1.09 | Decommissioning |
Where a material liability for the removal of production facilities and site restoration at the end of the productive life of a field exists, a provision for decommissioning is recognised. The amount recognised is the present value of estimated future expenditure determined in accordance with local conditions and requirements. The cost of the relevant tangible fixed asset is increased with an amount equivalent to the provision and depreciated on a unit of production basis. Changes in estimates are recognised prospectively, with corresponding adjustments to the provision and the associated fixed asset. | |
1.10 | Property, plant and equipment |
Property, plant and equipment is stated in the Balance Sheet at cost less accumulated depreciation and any recognised impairment loss. Depreciation on property, plant and equipment other than exploration and production assets, is provided at rates calculated to write off the cost less estimated residual value of each asset on a straight-line basis over its expected useful economic life of between three and eight years. | |
1.11 | Inventories |
Inventories are stated at the lower of cost and net realisable value. Cost is determined by the weighted average cost formula, where cost is determined from the weighted average of the cost at the beginning of the period and the cost of purchases during the period. Net realisable value represents the estimated selling price less all estimated costs of completion and costs to be incurred in marketing, selling and distribution. |
1.12 | Revenue recognition |
Revenue represents amounts invoiced in respect of sales of oil and gas exclusive of indirect taxes and excise duties and is recognised on delivery of product. Interest income is accrued on a time basis, by reference to the principal outstanding and at the effective rate applicable, which is the rate that exactly discounts estimated future cash receipts through the expected life of the financial asset to that asset's net carrying amount. | |
1.13 | Foreign currencies |
Transactions in foreign currencies are translated at the exchange rate ruling at the date of each transaction. Foreign currency monetary assets and liabilities are retranslated using the exchange rates at the balance sheet date. Gains and losses arising from changes in exchange rates after the date of the transaction are recognised in the income statement. Non‑monetary assets and liabilities that are measured in terms of historical cost in a foreign currency are translated at the exchange rate at the date of the original transaction. | |
In the consolidated financial statements, the net assets of the Company are translated into its presentation currency at the rate of exchange at the balance sheet date. Income and expense items are translated at the average rates for the period. The resulting exchange differences are recognised in equity and included in the translation reserve. | |
1.14 | Operating leases |
The costs of all operating leases are charged against operating profit on a straight-line basis at existing rental levels. Incentives to sign operating leases are recognised in the income statement in equal instalments over the term of the lease. | |
1.15 | Financial instruments |
Financial assets and financial liabilities are recognised on the Group's balance sheet when the Group becomes a party to the contractual provisions of the instrument. The Group does not currently utilise derivative financial instruments. | |
The particular recognition and measurement methods adopted are disclosed below: | |
(i) | Cash and cash equivalents |
Cash and cash equivalents comprise cash on hand and demand deposits and other short-term highly liquid investments that are readily convertible to a known amount of cash and are subject to an insignificant risk of changes in value. | |
(ii) | Trade receivables |
Trade receivables do not carry any interest and are stated at their nominal value as reduced by appropriate allowances for estimated irrecoverable amounts. | |
(iii) | Trade payables |
Trade payables are not interest-bearing and are stated at their nominal value. | |
(iv) | Investments |
Investments in subsidiaries are stated at cost and reviewed for impairment if there are indications that the carrying value may not be recoverable. | |
(v) | Equity investments |
Equity instruments issued by the Company and the Group are recorded at the proceeds received, net of direct issue costs. | |
1.16 | Finance costs |
Borrowing costs are recognised as an expense when incurred. |
1.17 | Borrowings |
Borrowings are recognised initially at fair value, net of any applicable transaction costs incurred. Borrowings are subsequently carried at amortised cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognised in the income statement over the period of the borrowings using the effective interest method (if applicable).
Interest on borrowings is accrued as applicable to that class of borrowing. | |
1.18 | Provisions |
Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. | |
When the Group expects some or all of a provision to be reimbursed, for example under an insurance contract, the reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the income statement net of any reimbursement. | |
1.19 | Dividends |
Dividends are reported as a movement in equity in the period in which they are approved by the shareholders. | |
1.20 | Taxation |
The tax expense represents the sum of the tax currently payable and deferred tax. | |
Current tax, including UK corporation and overseas tax, is provided at amounts expected to be paid (or recovered) using the tax rates and laws that have been enacted or substantially enacted by the balance sheet date. | |
Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial information and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the balance sheet liability method. Deferred tax liabilities are generally recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised. Such assets and liabilities are not recognised if the temporary difference arises from goodwill or from the initial recognition (other than in a business combination) of other assets and liabilities in a transaction that affects neither the tax profit nor the accounting profit. | |
Deferred tax liabilities are recognised for taxable temporary differences arising on investments in subsidiaries and associates, and interests in joint ventures, except where the Group is able to control the reversal of the temporary difference and it is probable that the temporary difference will not reverse in the foreseeable future. | |
The carrying amount of deferred tax assets is reviewed at each balance sheet date and adjusted to the extent that it is probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered. | |
Deferred tax is calculated at the tax rates that are expected to apply in the period when the liability is settled or the asset is realised. Deferred tax is charged or credited in the income statement, except when it relates to items charged or credited directly to equity, in which case the deferred tax is also dealt with in equity. |
1.21 | Impairment of assets |
At each balance sheet date, the Group assesses whether there is any indication that its property, plant and equipment and intangible assets have been impaired. Evaluation, pursuit and exploration assets are also tested for impairment when reclassified to oil and natural gas assets. If any such indication exists, the recoverable amount of the asset is estimated in order to determine the extent of the impairment, if any. If it is not possible to estimate the recoverable amount of the individual asset, the recoverable amount of the cash‑generating unit to which the asset belongs is determined. | |
The recoverable amount of an asset or a cash‑generating unit is the higher of its fair value less costs to sell and its value in use. The value in use is the present value of the future cash flows expected to be derived from an asset or cash‑generating unit. This present value is discounted using a pre‑tax rate that reflects current market assessments of the time value of money and of the risks specific to the asset, for which future cash flow estimates have not been adjusted. If the recoverable amount of an asset is less than its carrying amount, the carrying amount of the asset is reduced to its recoverable amount. That reduction is recognised as an impairment loss. | |
The Group's impairment policy is to recognise a loss relating to assets carried at cost less any accumulated depreciation or amortisation immediately in the income statement. | |
Goodwill acquired in a business combination is, from the acquisition date, allocated to each of the cash‑generating units, or groups of cash‑generating units, that are expected to benefit from the synergies of the combination. Goodwill is tested for impairment at least annually, and whenever there is an indication that the asset may be impaired. An impairment loss is recognised or cash‑generating units, if the recoverable amount of the unit is less than the carrying amount of the unit. The impairment loss is allocated to reduce the carrying amount of the assets of the unit by first reducing the carrying amount of any goodwill allocated to the cash‑generating unit, and then reducing the other assets of the unit, pro rata on the basis of the carrying amount of each asset in the unit. | |
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. | |
1.22 | Business combinations |
Subsidiaries are all entities (including special purpose entities) over which the group has the power to govern the financial and operating policies generally accompanying a shareholding of more than one half of the voting rights. The existence and effect of potential voting rights that are currently exercisable or convertible are considered when assessing whether the group controls another entity. The group also assesses existence of control where it does not have more than 50% of the voting power but is able to govern the financial and operating policies by virtue of de-facto control. De-facto control may arise in circumstances where the size of the group's voting rights relative to the size and dispersion of holdings of other shareholders give the group the power to govern the financial and operating policies, etc.
Subsidiaries are fully consolidated from the date on which control is transferred to the group. They are deconsolidated from the date that control ceases.
The group applies the acquisition method to account for business combinations. The consideration transferred for the acquisition of a subsidiary is the fair values of the assets transferred, the liabilities incurred to the former owners of the acquiree and the equity interests issued by the group. The consideration transferred includes the fair value of any asset or liability resulting from a contingent consideration arrangement. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The group recognises any non-controlling interest in the acquiree on an acquisition- by-acquisition basis, either at fair value or at the non-controlling interest's proportionate share of the recognised amounts of acquiree's identifiable net assets.
Acquisition-related costs are expensed as incurred.
If the business combination is achieved in stages, the acquisition date fair value of the acquirer's previously held equity interest in the acquiree is remeasured to fair value at the acquisition date through profit or loss.
Any contingent consideration to be transferred by the group is recognised at fair value at the acquisition date. Subsequent changes to the fair value of the contingent consideration that is deemed to be an asset or liability is recognised in accordance with IAS 39 either in profit or loss or as a change to other comprehensive income. Contingent consideration that is classified as equity is not remeasured, and its subsequent settlement is accounted for within equity.
Goodwill is initially measured as the excess of the aggregate of the consideration transferred and the fair value of non-controlling interest over the net identifiable assets acquired and liabilities assumed. If this consideration is lower than the fair value of the net assets of the subsidiary acquired, the difference is recognised in profit or loss.
Inter-company transactions, balances, income and expenses on transactions between group companies are eliminated. Profits and losses resulting from inter-company transactions that are recognised in assets are also eliminated. Accounting policies of subsidiaries have been changed where necessary to ensure consistency with the policies adopted by the group |
1.23 | Share based payments |
Equity settled transactions: | |
The Group provides benefits to employees (including senior executives) of the Group in the form of share-based payments, whereby employees render services in exchange for shares or rights over shares (equity-settled transactions). | |
The cost of these equity-settled transactions with employees is measured by reference to the fair value of the equity instruments at the date at which they are granted. The fair value is determined by using a Black-Scholes model. | |
In valuing equity-settled transactions, no account is taken of any performance conditions, other than conditions linked to the price of the shares of Leni Gas & Oil Plc (market conditions) if applicable. | |
The cost of equity-settled transactions is recognised, together with a corresponding increase in equity, over the period in which the performance and/or service conditions are fulfilled, ending on the date on which the relevant employees become fully entitled to the award (the vesting period). | |
The cumulative expense recognised for equity-settled transactions at each reporting date until vesting date reflects (i) the extent to which the vesting period has expired and (ii) the Group's best estimate of the number of equity instruments that will ultimately vest. No adjustment is made for the likelihood of market performance conditions being met as the effect of these conditions is included in the determination of fair value at grant date. The Income Statement charge or credit for a period represents the movement in cumulative expense recognised as at the beginning and end of that period. | |
No expense is recognised for awards that do not ultimately vest, except for awards where vesting is only conditional upon a market condition. | |
If the terms of an equity-settled award are modified, as a minimum an expense is recognised as if the terms had not been modified. In addition, an expense is recognised for any modification that increases the total fair value of the share-based payment arrangement, or is otherwise beneficial to the employee, as measured at the date of modification. | |
If an equity-settled award is cancelled, it is treated as if it had vested on the date of cancellation, and any expense not yet recognised for the award is recognised immediately. However, if a new award is substituted for the cancelled award and designated as a replacement award on the date that it is granted, the cancelled and new award are treated as if they were a modification of the original award, as described in the previous paragraph. | |
The dilutive effect, if any, of outstanding options is reflected as additional share dilution in the computation of earnings per share. | |
1.24 | Segmental reporting |
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the board of directors that makes strategic decisions
The Group has a single business segment: oil and gas exploration, development and production. The business segment can be split into five geographical segments: Spain, USA, Trinidad & Tobago, 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 | Share based payments reserve |
This reserve is used to record the value of equity benefits provided to employees and directors as part of their remuneration and provided to consultants and advisors hired by the Group from time to time as part of the consideration paid. |
1.27 | 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. | |
1.28 | 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 | ||||||
Management has determined the operating segments based on the reports reviewed by the Board of Directors that are used to make strategic decisions.
The Board has determined there is a single business segment: oil and gas exploration, development and production. The business segment can be further split into five geographical segments: Spain, USA, Trinidad & Tobago, Cyprus and UK.
Spain, USA, and Trinidad, have been reported as the group's direct oil and gas producing entities, these are the group's only revenue generating operations. The UK is the Group's parent and administrative entity and is reported on accordingly.
The board considers the following external reporting to be appropriate to the current development of its strategic investment in Malta, this being combined with the Cypriot administration costs as one reported geographical segment of Cyprus, as the subsidiaries which hold these investments are incorporated therein. Further breakdown of each of these relative country investments is not seen to be informative at this time as a result of their current development stages, and are thus combined and reported under their investment entity . | |||||||
Corporate | Holding | Operating | Operating | Operating | Total | ||
Year ended 31 December 2011 | UK | Cyprus | Spain | Trinidad | US | ||
£'000 | £'000 | £'000 | £'000 | £'000 | £'000 | ||
Operating loss by geographical area | |||||||
Revenue (*) | - | - | 2,659 | 375 | 383 | 3,417 | |
Operating profit/(loss) | (1,267) | (35) | (675) | 197 | (424) | (2,204) | |
Impairment charge | - | - | (1,685) | - | - | (1,685) | |
Finance charges | (30) | - | - | - | - | (30) | |
Finance revenue | 4 | - | 4 | - | - | 8 | |
Profit/(loss) before taxation | (1,293) | (35) | (2,356) | 197 | (424) | (3,911) | |
Other information | |||||||
Depreciation and amortisation | 2 | - | 138 | 9 | 416 | 565 | |
Capital additions (including goodwill) | 3,092 | 348 | 3,547 | 200 | 28 | 7,215 | |
Segment assets | 3,090 | 1,846 | 9,288 | 199 | 5,780 | 20,203 | |
Financial assets | 341 | - | 648 | 62 | 111 | 1,162 | |
Inventory | - | - | 233 | - | - | 233 | |
Cash | 484 | - | 282 | 146 | 144 | 1,056 | |
Consolidated total assets | 3,915 | 1,846 | 10,451 | 407 | 6,035 | 22,654 | |
Segment liabilities | |||||||
Trade and other payables | (706) | (6) | (1,411) | (16) | (16) | (2,155) | |
Taxation | - | (13) | - | (44) | - | (57) | |
Borrowings | (718) | - | - | - | - | (718) | |
Deferred Consideration | (2,587) | - | - | - | - | (2,587) | |
Provisions | - | - | (799) | - | - | (799) | |
Consolidated total liabilities | (4,011) | (19) | (2,210) | (60) | (16) | (6,316) | |
(*) Revenues are derived from a single customer/partner within each of these operating countries.
2 | Turnover and segmental analysis (continued) | ||||||
Corporate | Holding | Operating | Operating | Operating | Total | ||
Year ended 31 December 2010 | UK | Cyprus | Spain | Trinidad | US | ||
£'000 | £'000 | £'000 | £'000 | £'000 | £'000 | ||
Operating loss by geographical area | |||||||
Revenue (*) | - | - | 1,396 | - | 868 | 2,264 | |
Operating (loss) | (1,315) | (18) | (626) | (20) | (1,424) | (3,403) | |
Impairment charge | - | - | - | - | (6,904) | (6,904) | |
Finance revenue | 15 | - | - | - | - | 15 | |
Profit/(loss) before taxation | (1,300) | (18) | (626) | (20) | (8,328) | (10,292) | |
Other information | |||||||
Depreciation and amortisation | - | - | 162 | - | 1,681 | 1,843 | |
Capital additions | - | 62 | 1,793 | - | 15,253 | 17,108 | |
Segment assets | - | 1,498 | 7,450 | - | 6,177 | 15,125 | |
Financial assets | 22 | 76 | 548 | - | 103 | 749 | |
Inventory | - | - | 96 | - | - | 96 | |
Cash | 3,744 | - | 22 | 53 | 33 | 3,852 | |
Consolidated total assets | 3,766 | 1,574 | 8,116 | 53 | 6,313 | 19,822 | |
Segment liabilities | |||||||
Trade and other payables | (297) | - | (233) | (1) | (24) | (555) | |
Provisions | - | - | (817) | - | - | (817) | |
Consolidated total liabilities | (297) | - | (1,050) | (1) | (24) | (1,372) | |
(*) Revenues are derived from a single customer/partner within each of these operating countries.
3 | Operating loss | 2011 | 2010 |
£ 000's | £ 000's | ||
Operating loss is arrived at after charging: | |||
Auditors' remuneration - audit | 40 | 19 | |
Auditors' remuneration - non audit services | - | - | |
Directors' emoluments - fees and salaries | 788 | 131 | |
Directors' emoluments - share based payments and options | 136 | 505 | |
Depreciation | 69 | 66 | |
Amortisation | 496 | 1,777 | |
Auditors remuneration for audit services above includes £20,879 (2010: £4,291) charges by MGI Gregoriou & Co Certified Public Accountants (Cyprus) relating to the audit of the subsidiary companies. | |||
4 | Employee information (excluding directors') | 2011 | 2010 |
Staff costs comprised: | £ 000's | £ 000's | |
Wages and salaries | 1,105 | 674 | |
Social security contributions | 243 | 176 | |
Total staff costs | 1,348 | 850 | |
The average number of employees on a full time equivalent basis during the year was as follows: | |||
Number | Number | ||
Administration | 4 | 5 | |
Operations | 20 | 14 | |
Total | 24 | 19 | |
5 | Taxation | 2011 | 2010 |
Analysis of charge/(credit) in period | £ 000's | £ 000's | |
Tax on ordinary activities | 155 | (5) | |
Factors affecting the tax charge for the period: | |||
Loss on ordinary activities before tax | (3,911) | (10,287) | |
Standard rate of corporation tax in the UK | 26%/28% | 28% | |
Loss on ordinary activities multiplied by the standard rate of corporation tax | (1,037) | (2,880) | |
Effects of: | |||
Non deductible expenses | 95 | - | |
Withholding tax on overseas interest | - | (5) | |
Overseas tax on profits | 155 | - | |
Future tax benefit not brought to account | 942 | 2,880 | |
Current tax charge for period | 155 | (5) | |
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 £4,493,410 (2010: £1,977,000) 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 (2010: nil). |
7 | Directors' emoluments | |||||
2011 | 2010 | |||||
£ 000's | £ 000's | |||||
Directors' remuneration | 924 | 1,176 | ||||
Directors Fees | Consultancy Fees | Share based payments | Total | |||
2011 | £000's | £000's | £000's | £000's | ||
Executive Directors | ||||||
David Lenigas | 12 | 240 | - | 252 | ||
Neil Ritson | 160 | - | - | 160 | ||
(****) | Fraser Pritchard | 6 | 149 | 61 | 216 | |
(*****) | Donald Strang | 12 | 156 | - | 168 | |
Non-Executive Directors | ||||||
(***) | Stephen Horton | 11 | 42 | 75 | 128 | |
201 | 587 | 136 | 924 | |||
2010 | £000's | £000's | £000's | £000's | ||
Executive Directors | ||||||
David Lenigas | 12 | 240 | - | 252 | ||
(**) | Neil Ritson | 19 | 4 | 327 | 350 | |
(****) | Fraser Pritchard | 12 | 156 | 13 | 181 | |
(*****) | Donald Strang | 12 | 156 | 133 | 301 | |
(*) | Jeremy Edelman | 12 | 48 | 32 | 92 | |
Non-Executive Directors | ||||||
(***) | Stephen Horton | - | - | - | - | |
67 | 604 | 505 | 1,176 | |||
No pension benefits are provided for any Director. | ||||||
(*) | Jeremy Edelman stepped down from the Board on 23 December 2010. | |||||
(**) | Neil Ritson was appointed to the Board on 19 November 2010 | |||||
(***) | Stephen Horton was appointed to the Board on 3 February 2011 | |||||
(****) | Fraser Pritchard stepped down from the Board on 30 June 2011 | |||||
(*****) | Donald Strang stepped down from the Board on 16 December 2011. | |||||
During the period a total of £200,500 (2010: £540,000) of consultancy fees, payable by an overseas subsidiary, were accrued to directors (as detailed in Note 23) and were capitalised in accordance with the Group's accounting policies.
In Q3 2011 it was decided that Executive Directors would defer their cash salary. As a result the CEO has not been paid since the 30th September 2011, however, his salary is continuing to be accrued within the financial statements. Consultancy fees for Executive Directors have also been suspended from October 2011, but are accrued in the accounts. | ||||||
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: | |||
2011 | 2010 | ||
Net loss after taxation (£000's) | (4,066) | (10,287) | |
Weighted average number of ordinary shares used in calculating basic loss per share (millions) | 950.1 | 683.2 | |
Weighted average number of ordinary shares used in calculating diluted loss per share (millions) | 1,131.3 | 822.1 | |
Basic loss per share (expressed in pence) | (0.43) | (1.51) | |
Diluted loss per share (expressed in pence) | (0.43) | (1.51) | |
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 | 2011 | 2010 |
£ 000's | £ 000's | ||
Bank interest receivable | 8 | 2 | |
Interest income on loan to associate | - | 13 | |
8 | 15 |
10 | Intangible assets | 2011 | ||||
Oil and gas properties | Deferred exploration expenditure | Decommissioning costs | Goodwill | Total | ||
Group | £000's | £000's | £000's | £000's | £000's | |
Cost | ||||||
As at 1 January 2011 | 21,470 | 1,498 | 817 | - | 23,785 | |
Additions | 3,769 | 348 | - | 3,083 | 7,200 | |
Disposal | - | - | - | - | - | |
Foreign exchange difference on translation | (204) | - | (18) | - | (222) | |
As at 31 December 2011 | 25,035 | 1,846 | 799 | 3,083 | 30,763 | |
Amortisation and Impairment | ||||||
As at 1 January 2011 | 8,652 | - | 8 | - | 8,660 | |
Amortisation | 493 | - | 3 | - | 496 | |
Disposal | - | - | - | - | - | |
Impairment charge | 1,685 | - | - | - | 1,685 | |
Foreign exchange difference on translation | (37) | - | - | - | (37) | |
As at 31 December 2011 | 10,793 | - | 11 | - | 10,804 | |
Net book value | ||||||
As at 31 December 2011 | 14,242 | 1,846 | 788 | 3,083 | 19,959 | |
As at 31 December 2010 | 12,818 | 1,498 | 809 | - | 15,125 | |
Impairment review | ||||||
At 31 December 2011, the Directors carried out an impairment review and, other than the impairment charge as detailed in Note 12, have confirmed that no further provision is currently required. | ||||||
10 | Intangible assets (continued) | 2010 | ||||
Oil and gas properties | Deferred exploration expenditure | Decommissioning costs | Goodwill | Total | ||
Group | £000's | £000's | £000's | £000's | £000's | |
Cost | ||||||
As at 1 January 2010 | 5.444 | 3.106 | 858 | - | 9,408 | |
Additions | 17,046 | 62 | - | - | 17,108 | |
Disposal | - | (1,670) | - | - | (1,670) | |
Foreign exchange difference on translation | (1,020) | - | (41) | - | (1,061) | |
As at 31 December 2010 | 21,470 | 1,498 | 817 | - | 23,785 | |
Amortisation and Impairment | ||||||
As at 1 January 2010 | 42 | 1,670 | 7 | - | 1,719 | |
Amortisation | 1,774 | - | 3 | - | 1,777 | |
Disposal | - | (1,670) | - | - | (1,670) | |
Impairment charge | 6,904 | - | - | - | 6,904 | |
Foreign exchange difference on translation | (68) | - | (2) | - | (70) | |
As at 31 December 2010 | 8,652 | - | 8 | - | 8,660 | |
Net book value | ||||||
As at 31 December 2010 | 12,818 | 1,498 | 809 | - | 15,125 | |
As at 31 December 2009 | 5,402 | 1,436 | 851 | - | 7,689 | |
11 | Property, plant and equipment | 2011 | 2011 |
Group | Company | ||
£ 000's | £ 000's | ||
Cost | |||
As at 1 January 2011 | 538 | - | |
Additions | 15 | 9 | |
Disposals | - | - | |
Foreign exchange difference on translation | (12) | - | |
As at 31 December 2011 | 541 | - | |
Depreciation | |||
As at 1 January 2011 | 235 | - | |
Depreciation | 69 | 2 | |
Eliminated on disposal | - | - | |
Foreign exchange difference on translation | (7) | - | |
As at 31 December 2011 | 297 | 2 | |
Net book value | |||
As at 31 December 2011 | 244 | 7 | |
As at 31 December 2010 | 303 | - | |
Impairment review | |||
At 31 December 2011, the Directors have carried out an impairment review and confirmed that no provision is currently required. | |||
11 | Property, plant and equipment (continued) | 2010 | 2010 |
Group | Company | ||
Group | £ 000's | £ 000's | |
Cost | |||
As at 1 January 2010 | 564 | - | |
Additions | - | - | |
Disposals | - | - | |
Foreign exchange difference on translation | (26) | - | |
As at 31 December 2010 | 538 | - | |
Depreciation | |||
As at 1 January 2010 | 178 | - | |
Depreciation | 66 | - | |
Eliminated on disposal | - | - | |
Foreign exchange difference on translation | (9) | - | |
As at 31 December 2010 | 235 | - | |
Net book value | £'000 | £'000 | |
As at 31 December 2010 | 303 | - | |
As at 31 December 2009 | 386 | - | |
12 | Impairment charge |
The Board of Directors undertook an impairment review of the Group's assets as at 31 December 2011 and in view of subsequent events to the Balance Sheet date. The format of the review was to assess the carrying value of assets at 31 December 2011 by country. Due to external market information gained from the marketing of our Spanish asset, the Directors felt it was prudent to reduce the carrying value of the Spanish Subsidiary's (CPS) intangible assets to a level which better reflect the economic value of the business. Subsequently the value of the Group's investment in CPS's intangible assets have been written down by £1.7 m. The remainder of the Group's assets are considered by the Board, to be appropriately valued at their current economic values. |
13 | Investment in subsidiaries | 2011 | ||||
Shares in Group undertaking | £ 000's | |||||
Company | ||||||
Cost | ||||||
As at 1 January 2011 | 2 | |||||
Additions | 3,083 | |||||
As at 31 December 2011 | 3,085 | |||||
The parent company of the Group holds more than 20% of the share capital of the following companies:
| ||||||
Company | Country of Registration | Proportion held | Nature of business | |||
Direct | ||||||
Leni Gas & Oil Holdings Ltd | Cyprus | 100% | Holding Company | |||
Leni Trinidad Ltd | Trinidad & Tobago | 100% | Oil and Gas Production and Exploration Company | |||
Goudron E&P Ltd | Trinidad & Tobago | 100% | Investment Company | |||
Indirect | ||||||
Via Leni Gas & Oil Holdings Ltd | ||||||
Leni Gas & Oil Investments Ltd | Cyprus | 100% | Investment Company | |||
Leni Investments Cps Ltd | Cyprus | 100% | Investment Company | |||
Leni Investments Byron Ltd | Cyprus | 100% | Investment Company | |||
Leni Investments Trinidad Ltd | Cyprus | 100% | Investment Company | |||
Via Leni Investments Cps Ltd | ||||||
Compania Petrolifera de Sedano S.L. | Spain | 100% | Oil and Gas Production and Exploration Company | |||
Via Leni Investments Byron Ltd | ||||||
Leni Gas and Oil US Inc. | United States | 100% | Oil and Gas Production and Exploration Company | |||
14 | Trade and other receivables | 2011 | 2010 | ||
Group | Company | Group | Company | ||
£ 000's | £ 000's | £ 000's | £ 000's | ||
Current trade and other receivables | |||||
Trade receivables | 636 | 2,764 | 296 | - | |
VAT receivable | 76 | 34 | 14 | 14 | |
Other receivables | 372 | 240 | 1 | 1,970 | |
Prepayments | 78 | 67 | 135 | 23 | |
Total | 1,162 | 3,105 | 446 | 2,007 | |
Non-current trade and other receivables | |||||
Loans due from subsidiaries | - | 24,467 | - | 20,824 | |
Total | - | 24,467 | - | 20,824 | |
The loans due from subsidiaries are interest free and have no fixed repayment date. | |||||
15 | Inventories | 2011 | 2010 | ||
Group | Company | Group | Company | ||
£ 000's | £ 000's | £ 000's | £ 000's | ||
Inventories - Crude Oil | 233 | - | 96 | - | |
16 | Trade and other payables | 2011 | 2010 | ||
Group | Company | Group | Company | ||
£ 000's | £ 000's | £ 000's | £ 000's | ||
Current trade and other payables | |||||
Trade Payables | 1,512 | 376 | 488 | 254 | |
Deferred consideration | 737 | 737 | - | - | |
Taxation | 57 | - | - | - | |
Accruals | 643 | 330 | 67 | 43 | |
Total | 2,949 | 1,443 | 555 | 297 | |
Non-current trade and other payables | |||||
Deferred consideration | 1,850 | 1,850 | - | - | |
Total | 1,850 | 1,850 | - | - | |
17 | Borrowings | 2011 | 2010 | ||
Group | Company | Group | Company | ||
£ 000's | £ 000's | £ 000's | £ 000's | ||
Non-current | |||||
Loans - other (unsecured) | 688 | 688 | - | - | |
Interest payable on borrowings | 30 | 30 | - | - | |
718 | 718 | - | - | ||
The loans due to other parties carried an interest charge of 10% and a repayment date of the 30 June 2013. The carrying amounts of short-term borrowings approximate their fair value, and are all denominated in pounds sterling. | |||||
Equity Line Facility
The Company has secured a three year Equity Line Facility ("ELF") of up to £5 million with Dutchess Opportunity Cayman Fund Ltd ("Dutchess"). The ELF has been arranged by First Columbus LLP ("First Columbus"), Dutchess's joint venture partner in the UK.
The ELF offers the Company ongoing access to capital as it enables the Company to obtain funding from Dutchess at any time during the next three years by way of subscription for new ordinary shares in the Company. Subscriptions will be priced at a 5 per cent discount to the market price and will take place at timings and intervals and in sizes solely determined by the Company, subject to the agreed mechanisms specified under the ELF.
The ELF may be drawn down in tranches linked to the Company's average daily trading volume in the three days prior to the notice of draw down or in other specified amounts. The Company is able to specify a minimum acceptable price for each tranche to prevent shares being sold in the market at an unacceptable discount. Currently LGO has drawndown £226,700 on the ELF facility to 31 December 2011.
| |||||
18 | Provisions | 2011 | 2010 | ||
Provision for decommissioning costs | Group | Company | Group | Company | |
£ 000's | £ 000's | £ 000's | £ 000's | ||
At 1 January | 817 | - | 858 | - | |
Foreign exchange difference on translation | (18) | - | (41) | - | |
At 31 December | 799 | - | 817 | - | |
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. | |||||
19 | Share capital | |||
Called up, allotted, issued and fully paid | Number of shares | Nominal value | ||
£ 000's | ||||
As at 1 January 2009 | 608,254,965 | 304 | ||
20 July 2010 cash at 2p per share | 75,000,000 | 38 | ||
27 July 2010 non cash for staff incentives | 12,666,667 | 6 | ||
2 September 2010 cash at 2p per share | 40,000,000 | 20 | ||
16 November 2010 cash at 3p per share | 183,333,333 | 92 | ||
As at 31 December 2010 | 919,254,965 | 460 | ||
21 November Cash at 1.19p per share | 4,200,000 | 2 | ||
21 November 2011 cash at 0.93p per share | 19,000,000 | 10 | ||
29 November 2011 cash at 0.50p per share | 302,000,000 | 151 | ||
29 November 2011 cash at 0.50p per share | 15,000,000 | 7 | ||
As at 31 December 2011 | 1,259,454,965 | 630 | ||
During the year 340 million shares were issued (2010: 311 million). | ||||
Total share options in issue | ||||
During the year 32.5 million options were issued (2010: 25 million). | ||||
As at 31 December 2011 the options in issue were: | ||||
Exercise Price | Expiry Date | Options in Issue | ||
3p | 16 March 2012 | 16,000,000 | ||
2.5p | 09 June 2013 | 16,300,000 | ||
3p | 18 November 2013 | 10,000,000 | ||
4p | 18 November 2013 | 5,000,000 | ||
5p | 18 November 2013 | 5,000,000 | ||
6p | 18 November 2013 | 5,000,000 | ||
3p | 31 January 2013 | 10,000,000 | ||
4p | 31 January 2013 | 2,500,000 | ||
5p | 31 January 2014 | 5,000,000 | ||
3p | 03 May 2014 | 5,000,000 | ||
4p | 03 May 2014 | 3,500,000 | ||
5p | 03 May 2014 | 3,500,000 | ||
6p | 03 May 2014 | 3,000,000 | ||
As at 31 December 2011 | 89,800,000 | |||
No options lapsed or were cancelled and no options were exercised during the period. | ||||
Total warrants in issue | ||||
During the year, no warrants were issued (2010: nil) | ||||
As at 31 December 2011 the warrants in issue were; | ||||
Exercise Price | Expiry Date | Warrants in Issue 31 December 2010 | ||
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, were cancelled or exercised during the period. (2010: nil) | ||||
20 | Share based payment arrangements | ||||||||
Share options | |||||||||
The Company has an established an employee share option plan to enable the issue of options as part of remuneration of key management personnel and Directors to enable the purchase of shares in the entity. Options were granted under the plan for no consideration. Options were granted for a three or 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.
Details of the current unexpired share options at the date of this report are as shown in the table below: | |||||||||
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 | 2.5 | 9 June 2013 | 2.39 | 2.39 | ||
Jeremy Edelman | 9 June 2008 | 9 June 2010 | 1,000,000 | 2.5 | 9 June 2013 | 2.39 | 2.39 | ||
Donald Strang | 9 June 2008 | 9 June 2009 | 3,000,000 | 2.5 | 9 June 2013 | 2.39 | 2.39 | ||
Donald Strang | 9 June 2008 | 9 June 2010 | 3,000,000 | 2.5 | 9 June 2013 | 2.39 | 2.39 | ||
Fraser Pritchard | 9 June 2008 | 9 June 2009 | 1,000,000 | 2.5 | 9 June 2013 | 2.39 | 2.39 | ||
Fraser Pritchard | 9 June 2008 | 9 June 2010 | 1,000,000 | 2.5 | 9 June 2013 | 2.39 | 2.39 | ||
Neil Ritson | 19 November 2010 | 19 November 2010 | 10,000,000 | 3 | 18 November 2013 | 1.57 | 1.57 | ||
Neil Ritson | 19 November 2010 | 19 November 2010 | 5,000,000 | 4 | 18 November 2013 | 1.32 | 1.32 | ||
Neil Ritson | 19 November 2010 | 19 November 2010 | 5,000,000 | 5 | 18 November 2013 | 1.13 | 1.13 | ||
Neil Ritson | 19 November 2010 | 19 November 2010 | 5,000,000 | 6 | 18 November 2013 | 0.98 | 0.98 | ||
Steve Horton | 3 February 2011 | 3 February 2011 | 5,000,000 | 5 | 31 January 2014 | 1.82 | 1.82 | ||
Garry Stoker | 3 May 2011 | 3 May 2011 | 5,000,000 | 3 | 3 May 2014 | 2.10 | 2.10 | ||
Garry Stoker | 3 May 2011 | 3 May 2011 | 3,500,000 | 4 | 3 May 2014 | 1.92 | 1.92 | ||
Garry Stoker | 3 May 2011 | 3 May 2011 | 3,500,000 | 5 | 3 May 2014 | 1.78 | 1.78 | ||
Garry Stoker | 3 May 2011 | 3 May 2011 | 3,000,000 | 6 | 3 May 2014 | 1.66 | 1.66 | ||
Fraser Pritchard | 20 July 2011 | 20 July 2011 | 10,000,000 | 3 | 31 January 2013 | 0.54 | 0.54 | ||
Fraser Pritchard | 20 July 2011 | 20 July 2011 | 2,500,000 | 4 | 31 January 2013 | 0.32 | 0.32 | ||
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 | 73,800,000 | ||||||||
The fair value of the options vested during the period was £0.42 million (2010: £0.37 million). 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.
| |||||||||
The following table lists the inputs to the model used for the period ended 31 December 2011:
| |||||||||
3 February 2011 | 3 May 2011 | 20 July 2011 | |||||||
Dividend Yield (%) | - | - | - | ||||||
Expected Volatility (%) | 96.3 | 101.7 | 53.34 | ||||||
Risk-free interest rate (%) | 2.0 | 2.0 | 2 | ||||||
Share price at grant date (pence) | 3.00 | 3.20 | 2.54 | ||||||
The expected volatility reflects the assumption that the historical volatility is indicative of future trends, which may, not necessarily be the actual outcome.
| |||||||||
21 | 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 | 2011 | 2010 | |||||
£ 000's | £ 000's | ||||||
Sterling | 484 | 3,744 | |||||
Euros | 282 | 22 | |||||
US Dollars | 144 | 33 | |||||
Trinidad Dollars | 146 | 53 | |||||
1,056 | 3,852 | ||||||
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, and Trinidadian 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 | (222) | 222 | (824) | 824 | |||
US Dollar | (42) | 42 | (602) | 602 | |||
Trinidad Dollar | 6 | (6) | 4 | (4) | |||
(258) | 258 | (1,422) | 1,422 | ||||
Rates of exchange to £1 used in the financial statements were as follows: | |||||||
| As at 31 December 2011 | Average for the relevant consolidated period to 31 December 2011 | As at 31 December 2010 | Average for the relevant consolidated period to 31 December 2010 | |||
Euro | 1.194 | 1.152 | 1.1674 | 1.1651 | |||
US Dollar | 1.546 | 1.604 | 1.5470 | 1.5448 | |||
Trinidad Dollar | 9.874 | 10.232 | 9.9900 | 9.9619 | |||
22 | Commitments and contingencies |
As at 31 December 2011, the Company had the following material commitments: | |
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. | |
Contingencies On appointment on 19 November 2010, Mr Neil Ritson, as part of his remuneration package, will be granted 20 million ordinary shares upon the Company share price reaching 20 pence prior to 31 December 2012. |
23 | Related party transactions | |||||
Transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note. Transactions between other related parties are discussed below. | ||||||
During the period, the Company accrued the following consultancy fees to the Company's directors for work performed in relation to an overseas subsidiary. These fees have been recharged to this subsidiary as follows : | ||||||
(i) | £240,000 to David Lenigas (2010: £228,000), | |||||
(ii) | £156,000 to Donald Strang (2010: £156,000), | |||||
(iii) | £149,000 to Fraser Pritchard (2010:£156,000). | |||||
(iv) | £42,000 to Stephen Horton (2010: nil). | |||||
(v) | Total accrued £200,500 (2010:£540,000). | |||||
During the period, two directors who previously made loans to the parent company, had these loans fully repaid and no balance remained outstanding at the end of the year. The loans were made unsecured, with no fixed repayment period and non-interest bearing. | ||||||
Remuneration of Key Management Personnel | ||||||
The remuneration of the Directors and other key management personnel of the Group is set out below in aggregate for each of the categories specified in IAS24 Related party Disclosures. | ||||||
2011 | 2010 | |||||
£ 000's | £ 000's | |||||
Short-term employee benefits | 733 | 438 | ||||
Share-based payments | 421 | 610 | ||||
1,154 | 1,048 | |||||
24 | Events after the reporting period |
On the 25th January 2012, Leni Gas & Oil plc announced a Partnership agreement in Trinidad. Range Resources Limited agreed to jointly develop their interests in the Eastern Fields Area onshore southern Trinidad, including the Goudron fields. A binding Heads of Agreement was signed between Range and LGO. Range will acquire a 30% interest in Goudron E&P Limited in return for contributing US$4 million at completion.
On the 2nd May 2012, Leni Gas & Oil plc confirmed that it had granted the preferred bidder for its Spanish assets exclusivity until 31st May 2012 to complete definitive documentation, although it was noted that this could not be guaranteed. |
25 | Profit and loss account of the parent company |
As permitted by section 408 of the Companies Act 2006, the profit and loss account of the parent company has not been separately presented in these accounts. The parent company loss for the period was £ 1.293 million (2010: £1.295 million). |
26 | Business combinations | ||||
Acquisition of Goudron E&P Limited ("Goudron") | |||||
On 3 October 2011, Leni Gas and Oil plc ("LGO") acquired a 100% interest in Goudron for a consideration of approximately £3,083,000. The consideration was settled by an initial payment of £617,000 and will be followed by additional stage payments totalling £2,466,000 once specific conditions have been met, including specific contract assignment and milestones production levels. | |||||
Goudron (100%) | Goudron (100%) | Fair Value | Fair Value on | ||
(Book Value) | (Book Value) | Adjustment | acquisition | ||
TTD | £ 000's | £ 000's | £ 000's | ||
Non-Current Assets | |||||
Intangible | - | - | - | - | |
Current Assets | |||||
Cash | 1,000 | - | - | - | |
Total Assets | 1,000 | - | - | - | |
Payables | - | - | - | - | |
Fair value of Net Assets | 1,000 | - | - | - | |
Consideration for acquisition | |||||
Cash paid | 617 | ||||
Deferred cash consideration | 2,466 | ||||
Fair value of net assets acquired | - | ||||
Goodwill arising on acquisition | 3,083 | ||||
The cash inflow on acquisition was as follows; | £ 000's | ||||
Net cash acquired with subsidiary | - | ||||
Note to the announcement:
The financial information set out in this announcement does not constitute the Company's statutory accounts for the years ended 31 December 2011 or 2010. The financial information for the year ended 31 December 2010 is derived from the statutory accounts for that year. The audit of statutory accounts for the year ended 31 December 2011 is complete. The auditors reported on those accounts, their report was unqualified and did not include references to any matters to which the auditors drew attention to by way of emphasis without qualifying their report.
Enquiries:
Leni Gas & Oil plc
David Lenigas, Executive Chairman
Neil Ritson, Chief Executive Officer
Tel: +44 (0) 20 7016 5103
Beaumont Cornish Limited
Roland Cornish / Rosalind Hill Abrahams
Tel: +44 (0) 20 7628 3396
Panmure Gordon plc
Katherine Roe / Hannah Woodley
Tel: +44 (0) 20 7459 5744
Pelham Bell Pottinger
Mark Antelme / Henry Lerwill
Tel: +44 (0)20 7861 3232