3rd Jun 2011 16:05
For Immediate Release
3 June 2011
LENI GAS AND OIL PLC
("LGO" or the "Company")
Annual Report and Accounts 2010 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 2010 will be posted to Shareholders on Tuesday, 7 June 2011, together with a Notice of Annual General Meeting ("AGM"), and both documents and a copy of this announcement will be available from the Company's website, www.lenigasandoil.co.uk. The AGM will take place on 30 June 2011 at 11.00 am at the offices of Panmure Gordon & Co. plc Moorgate Hall, 155 Moorgate, London, EC2M 6XB.
Highlights
OPERATIONS
·; Total production during the reporting period in Spain of 32,785 bbls oil and 12 mmscf gas (34,984 boe), with beneficial interest production in Gulf of Mexico of 12,913 boe and in Trinidad of 6,707 bbls oil.
·; Modernisation of the Spanish production facilities and well sites is underway as part of a multi-year investment programme designed to attain higher standards of environmental compliance and technical integrity
·; Exercise of options to 20% (16.5% net interest) in two Gulf of Mexico development opportunities; Ship Shoal 180 and South Marsh Island 6
·; Prospect identification and delineation work has continued with the recognition of numerous opportunities, including additional reservoirs in the Ayoluengo Field and deeper potential in shale gas throughout the area of LGO operations
·; Contracted with Praxair to jointly study the injection of Nitrogen into the Ayoluengo Field in the form of an Enhanced Oil Recovery project
·; Hontomin-2 well on the Hontomin Field in Spain recompleted and placed on-line in October 2010 at an initial flow rate of 112 bopd, producing 2,142 bbls oil in the reporting period
·; Signed an initial agreement to jointly explore for unconventional gas in the Cantabrian Basin with RAG and Sorgenia
·; Completed acquisition of a 3D seismic survey over the Hontomin Field in collaboration with Spanish state institute, CIUDEN
·; The grant in December of a field-wide environmental permit at Ayoluengo to support the proposed production enhancement projects
·; Plans completed for a major well intervention campaign to be conducted in the Ayoluengo Field during 2011.
CORPORATE
·; Long term oil sales contract signed with BP to off-take the majority of Spanish future production to their Castellon refinery from late 2011 onwards
·; Completed various framework support agreements with technical providers to provide geosciences, production engineering, operations engineering and safety environmental services to the countries of operation
·; Raised £7.8 million in new share equity through the issue of 298.3 million ordinary shares to support ongoing activities and accelerate the redevelopment of the Spanish assets.
FINANCIALS
·; Gross profit of £0.52 million (2009: £1.05 million)
·; Pre-tax group loss of £10.29 million (2009: £2.06 million) mainly attributable to impairment charge of £6.9 million relating to provision for write-down of Gulf of Mexico investments to reflect the uncertainty in the recoverable reserves.
TARGETS FOR 2011
·; Expand the production base in Spain through recompletion of the existing main producing wells and Hontomin-2
·; Increase processing capacity in Spain for delivering sales oil to multiple customers including BP
·; Apply for additional exploration licences in Northern Spain to expand the Company's exposure to both conventional and unconventional plays
·; Expand the production base in the GoM fully utilising the Eugene Island-184 facilities
·; Initiate development drilling of both the Ship Shoal and South Marsh Island developments
·; Sign the new production licence for the Icacos Field in Trinidad and expand production capacity in the field
·; Enter into new commercial agreements in Trinidad to expand the Company's involvement in the Southern Basin
·; Finalise plans for the initial test phase of EOR at Ayoluengo Field and commence gas injection
·; Monitor developments in Malta and support the operator in efforts to fully evaluate and drill within the PSA.
NOTES
·; All figures are net LGO unless otherwise stated.
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
Chairman's Statement
I am pleased to report that considerable progress has been made in developing the long term potential of the Company's assets during 2010.
This is most notable in Spain, where we have increased our technical understanding of the reservoirs, producing wells and have started to improve the long-term viability of the facilities. Having now successfully received field-wide environmental permits we are in a position to advance the well intervention work and associated engineering. Due to the permitting process we have not had unrestricted access to the wells and as a result it has not been possible to increase production during the year to the extent envisaged; however, we are now confident that the planned work will be carried out in 2011.
The formation of contractual alliances with BP for oil sales, Praxair for EOR and with RAG and Sorgenia for the exploration for unconventional gas resources also marks a wholesale strengthening of our business and we will be building on the strengths of these alliances in 2011 and beyond.
The Company's strategy to acquire and enhance existing production assets with additional exploitation potential remains unchanged and is continuing to identify opportunities to increase both the equity position of existing assets and identify additional assets in the countries of operation for greater economies of scale. This is especially true in Trinidad where we hope to conclude a number of new commercial arrangements in 2011 based on extensive work undertaken in 2010 to identify opportunities in the onshore Southern Basin which will complement our existing Icacos Field knowledge that we have built up over the last few years.
Limited progress has been made in the Gulf of Mexico in 2010 where the Eugene Island 184 platform has not been operating at optimum capacity and reinvestment has been slow. This situation is changing in 2011 with the sale of the assets to a new operator, Marlin Energy LLC, who has the financial resources, technical know-how and commitment to rapidly address the numerous production enhancement opportunities that our joint portfolio offers. The Company has decided it is prudent to provide £6.9 million against its investment in Eugene Island Field to reflect any uncertainty in the recoverable reserves. Further information is provided in Note 12 to the financial statements in this report.
Malta is the Company's only non-producing asset though it has potential company-maker potential with a billion barrel resources base. During the reporting period, the Company and the joint venture operator have continued to progress the pre-drilling work program to improve the understanding of the highest potential drilling prospects. Due to the need for additional technical work and investment the operator has negotiated an extension to the pre-drilling exploration period of the PSA and it is now anticipated that drilling will occur in 2012.
The Company has continued to increase its organisational capability in all areas and has strengthened its management team in London through the inclusion of Neil Ritson as Chief Executive Officer. Mr Ritson is an experienced oil and gas professional with nearly 35 years of relevant experience in major and junior oil and gas companies. In early 2011 we have also added a non-executive director to our Board. Mr Steve Horton also brings over 35 years of relevant experience in oil and gas operations and in helping to grow junior companies. In May 2011 Garry Stoker was appointed as Chief Operating Officer designate and is expected to take up the role in June and may join the LGO Board of Directors at a later date.
Although the market conditions remained challenging we have been able to attain the required funding to continue unimpeded in our programme to strengthen the resource and revenue base of the Company and to continue to develop the technical and commercial foundations of the Company for the longer term. Funds raised in 2010 will be deployed to accelerate our programme of field enhancement in Spain and to ensure that opportunities in other areas, such as Trinidad, are progressed.
The Directors are delighted with the Company's performance during the reporting period as our operating position has been enhanced in all the key areas within our control and future risks have been mitigated. The commercial foundations of the business in all our countries of operation have been enhanced and we have a strong and flexible platform for future growth.
We would like to take this opportunity to thank all of our staff for their tremendous effort during 2010 and our shareholders for their ongoing support.
David Lenigas
Executive Chairman
3 June 2011
Operations Review
Leni Gas and Oil plc has a strategy to identify and acquire projects and businesses within the oil and gas sector that contain a development premium which can be unlocked through a combination of financial, commercial, and technical expertise.
The Company operates a low risk portfolio of production expansion assets in the US Gulf of Mexico, Spain 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 period activity in all countries of operation during the reporting period follows:
SPAIN:
LGO retains 100% ownership through its wholly owned subsidiary, Compañia Petrolifera de Sedano (CPS), in one production concession, La Lora (which contains the Ayoluengo producing oilfield), and three exploration permits; Basconcillos H, Huermeces and Valderredible, in north Spain. The permits are centrally located in the proven Basque-Cantabrian petroleum basin and span an area of over 550 sq km, with a processing facility designed to handle 10,000 bbls per day and store 21,000 bbls centred on the producing Ayoluengo oilfield which itself covers an area of 14 sq km.
As in 2009, the 2010 work program included various phases of well rehabilitation and stimulation on the Ayoluengo oilfield and various feasibility and appraisal activities in the exploration permits. In addition, extensive work was conducted at the Hontomin oilfield in the Huermeces permit.
Well intervention work in 2009 revealed the opportunity to gain additional production capacity from the existing multi-zone reservoirs of the Ayoluengo oilfield through well clean out, simulation and additional primary depletion from previously unexploited reservoir intervals. In order to further exploit the reserves in the field the Company proposed to enhance the technical integrity of the production facilities that had received little or no investment in the preceding 20 years of operation, and to raise the environmental standards to current norms. Applications were made for the required environmental permits, which were granted in December 2011.
Following grant of the required permits in December a plan for significant well intervention to be conducted in 2011 was developed and the Heads of Agreement previously signed with BP España (BP) in May to off-take the Company's future Spain production to BP's Castellón refinery in eastern Spain was ratified. That agreement which comes into force in mid-2011 allows CPS a period of 15 months to effect full implementation of the required field upgrades before shipping a minimum quantity, 1000 bopd, BP for refining.
During the first half of the year the original Chevron 3D seismic programme, which had been reprocessed in 2009, was re-interpreted by Equipoise Solutions Ltd (Equipoise) to improve the Company's understanding of the oilfield, de-risk production development programs and assess the deeper prospectivity which was reported in May 2010.
Reprocessing the Ayoluengo 3D seismic data resulted in a clearer structural image of the field, a more accurate determination of the fault positions and revised deterministic and probabilistic estimates of STOIIP for the producing Lower Cretaceous and Upper Jurassic reservoirs. The overall mean STOIIP was increased to 105.72 mmbo, (117.56 mmbo P10, 105.41 mmbo P50 and 94.19 mmbo P90). Historical cumulative production to mid-2010 has been 17.16 mmbo and 16.14 bcf (a total of 19.85 boe) equivalent to an overall recovery factor of just 18.8%.
Based on the re-interpretation oil in place for the main producing Lower Cretaceous and Upper Jurassic reservoirs was redistributed between the east and west flanks of the reservoirs (east reduced to 79.5 mmbo from 83.6 mmbo, and west increased to 27.3 mmbo from 20.6 mmbo), which gives historical recovery factors of 21% east and 5% west. Both these levels of recovery fall short of industry analogous and strongly suggest that the field has considerable remaining potential for secondary and enhance oil recovery techniques.
On the basis of this reassessment the Company has redefined the Ayoluengo development strategy based on the improved understanding of the reservoir to ensure the majority of the fifty three wells can contribute to maximising production. A two-tiered strategy on the existing producers and also the current shut-in wells will be adopted which seeks to initially gain maximum available capacity from open wells and secondarily focuses on Enhanced Oil Recovery (EOR) using gas or gas-alternating-water flooding as the primary re-pressurisation and sweep mechanism. After discussions with a number of experienced EOR providers an initial agreement was signed with Praxair España, S.L. a wholly owned subsidiary of Praxair Inc (Praxair). That agreement calls for a study phase followed by the signing of a definitive agreement in 2011 and it is initially envisaged that the main gas used will be nitrogen and that at least two rest sites will be deployed to establish the most effective EOR configuration.
The revised assessment reported by Equipoise in May 2010 also identified two new prospective hydrocarbon intervals in the Lower Jurassic lying underneath the Ayoluengo Lower Cretaceous and Upper Jurassic producing zones. A conventional hydrocarbon reservoir was identified between 2000m and 2300m subsurface and an unconventional gas prospect at depths down to 2700m subsurface.
The conventional reservoir interval has been drilled with oil shows in both the Ayoluengo discovery well, Ayoleungo-1, and in the nearby Hontomin-2 well. Although too early to make estimates of prospective resources this interval, if producible, could add substantially to the resource base of the existing field area. The Company plans to further test the extent and producibility of the conventional reservoir through the drilling of an appraisal well through the existing casing of one of the Ayoluengo wells in 2011.
The unconventional reservoir identified by Equipoise was assessed as likely to be locally mature for shale gas production based on the regional geological review and Ayoluengo re-interpretation. The size of the shale gas generation window below Ayoluengo is large and similar
structures in North America have proved to be on a considerable scale. Due to the age of the available data modelling has been limited and therefore the Company has formed a joint venture with Sorgenia International B.V (Sorgenia) and Rohöl-Aufsuchungs Aktiengesellschaft (RAG) to carry out a comprehensive local and regional evaluation study during 2011.
In 2009 a programme for the exploration permits was planned that included the design of an extended well test in the Huermeces Hontomin discovery, assessment of development options in the Basconcillos H gas discovery at Tozo-1, and the definition of the exploration activities throughout the acreage. The possible application for additional exploration permits in adjacent areas for both conventional and unconventional reservoirs was also considered.
In 2009 the Company announced completion of a joint development agreement with the Ciudad de la Energia (CIUDEN) for the research, testing and implementation of carbon dioxide sequestration (CCS) pilot sites in Spain. CIUDEN is a Spanish foundation incorporated by the Ministry of Industry, Trade and Tourism, the Ministry of the Environment and the Ministry of Science and Innovation within the Spanish Government. Under terms of the joint development agreement, works which are to be wholly funded by CIUDEN were performed on the Hontomin and were additionally considered on the western flank of Ayoluengo to assess CO2 injection, storage and enhanced oil recovery. In 2010 CIUDEN conducted a 10 sq km 3D seismic survey over the Hontomin oilfield. At end year the data had been processed and were being interpreted by CIUDEN prior to release to LGO. It is intended that in 2011 a joint work plan will be developed for Hontomin and that CIUDEN will potentially drill additional wells to test the injection of CO2 at the flanks of the field.
In August LGO commence the reopening of the Hontomin-2 well near the centre of the field in order to conduct an extended well test. The objective of which was to better appraise the long term production potential of the existing well and determine the optimum exploitation plan for the Hontomin Field which has an estimated mean STOIIP of 2.40 mmbo. The Hontomin-2 well was initially tested in 1968 at an initial rate of 700 bopd and was shut-in at a rate of 50 bopd. Re entry was commenced in late August with re-opening to 1397 metres before the well was recompleted with new 4 ½" production casing to increase the integrity of the well and placed on test in October 2011.
Initial test rates of some 170 bfpd were constrained by the temporary leased production facilities in use at the well site. Production was continued until end year and a total of 2,142 barrels of 32 deg API oil were produced. The well was monitored through early 2011 and then shut-in pending availability for wireline perforating equipment to open an additional 40 metre reservoir zone not previously produced in the well. All production from Hontomin will be transported 38 km to the production facilities at the Ayoluengo oilfield for processing and oil sales.
Following the feasibility study on the utilisation of gas from the Tozo-1 discovery no additional work was conducted in 2010. The well holds a small reserve that could provide injection gas for EOR at Ayoluengo or as sales gas, however, pending a decision on how to economically transport the gas no additional work has been justified.
In order to provide for the production expansion of both Ayoluengo and the surrounding prospects, the Company engaged the SGS Group to provide additional inspection, verification, testing and certification services. The Ayoluengo processing facility requires a major compliance programme to meet new European safety and environmental legislation, and modernisation of the facilities is also required to support higher volumes, artificial stimulation and multiple sales customers. These works were commenced in 2010 and will continue through 2011 and into 2012.
During the first half of 2011, an 80 tonne workover rig as well as wireline and cementing services were contracted to carry out a 7 to 12 well intervention campaign on the Ayoluengo main producing wells and on Hontomin-2. The programme, which is underway at the time of this report, is designed to re-perforate and clean the perforations of existing producing horizons and to perforate previously undeveloped reservoirs within these wells. Once completed this initial phase of redevelopment will be used to design further work on the field and to assist in planning further upgrades to the processing facilities.
Total net production during the reporting period (from the Ayoluengo and Hontomin oilfields) was 32,927 bbls of oil and 12.4 mmscf of gas, equivalent to 34,984 boe.
US GULF OF MEXICO:
LGO retains rights within sixteen blocks in the GoM encompass interests in leases West Cameron, South Marsh Island, Eugene Island, Ship Shoal, Grand Isle and Main Pass. The Company currently retains direct working interests in Eugene Island and Ship Shoal leases with exercise options in the remainder. Under terms of the2009 agreement with Byron Energy LLC (Byron Energy), LGO converted its 28.94% interest in Byron Energy to a 7.25% direct working interest in Eugene Island Blocks 183 and 184 south and a 3.625% direct working interest in Blocks 172 and 184 north (collectively referred to as "Eugene Island Field"). Net revenue interests range from 2.50540% to 6.04167%.
The Eugene Island Field is located 50 miles offshore Louisiana in approximately 80 feet of water, and was operated by Leed Petroleum plc (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. The Field redevelopment commenced in 2008 and in 2009 the production platform was delivering 6,000 boepd gross, at 2,500
bbls of oil and 21 mmscfd of gas. During 2009 production from Eugene Island declined from this initial figure due to natural depletion and the onset of water production from some of the wells. Decline continued in 2010 with an average gross production rate of 585 boepd. Several wells were considered for re-completion, however, until the wells have stopped producing the Bureau of Ocean Energy Management, Regulation and Enforcement (BOEMRE) (formally the MMS) will not approve the recompletion in new zones. This did not occur in the reporting period and as a consequence no new well recompletions were undertaken.
The Company exercised its rights in February 2010 on the South Marsh Island development (block Eugene Island 133). LGO retains exercise options on South Marsh Island block 8, Grand Isle blocks 95 and 100, Main Pass block 115 and West Cameron block 106. These options shall be notified for exercising once the operator issues the development plan and budget, this did not occur in 2010. The South Marsh Island development encompasses South Marsh Island block 8 and Eugene Island block 133. The development is located 90 miles offshore Louisiana in approximately 60 feet of water, was initially developed by Chevron and produced from numerous sands from 10,000 to 15,000 feet.
Under terms of the LDP-Byron Scouting Agreement, the Company retains an exercise option to acquire 29% of Byron's interests in these developments, equivalent to a direct 7.25% direct working interest, with net revenue interests between 5.8906% and 6.0417%.
In March 2010 the first Ship Shoal development well was successful drilled and evaluated at a restricted rate of 2,153 boepd (approximately 20% oil, 80% gas) after encountering 65 feet of true vertical thickness pay. Production from the first development well commenced in May 2010.
The Company also 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. Ship Shoal 180 contains two prospects with preliminary estimates on best case gross prospective resources in excess of 5 mmboe in the oil case and in excess of 12 bcf in the gas case (2 mmboe) whilst South Marsh Island 6 contains three prospects and one deep potential location with preliminary estimates on best case gross prospective resources in excess of 4 mmboe in the three shallow prospects and in excess of 25 bcf (4.2 mmboe) in the deep prospect.
In late March 2011 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 and at the date of this report production had not been recommenced. In May 2011 LDP sold its entire interest in all GoM properties to Marline Energy LLC (Marlin) who have assumed operatorship and are planning to restart both the production operations and also the capital investment programme on the LDP assets held in common with LGO. The Company has decided to provide £6.9 million against its investment in Eugene Island Field to reflect any uncertainty in the recoverable reserves.
Total net production during 2010 from the Eugene Island production asset was 6,617bbls of oil and 37.8mmscf of gas, equivalent to 12,913 boe.
TRINIDAD:
The Company retains 50% ownership to the Icacos oilfield, covering 1,900 acres, located on the Cedros Peninsula of Southern 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.
Throughout 2010 LGO has independently monitored operations and has assisted in raising production, reducing costs and improving HSE standards. A new production licence has been discussions with the Ministry of Energy during 2010 which includes the proposal for LGO to assume operatorship of the Icacos oilfield. A final draft of the new Private Petroleum Licence was agreed by the parties in May 2010, but due to Primera being part of a larger Group in receivership the licence was not signed.
The Company approached the receiver, PricewaterhouseCoopers Trinidad (PwC), regarding the acquisition of Primera's interests in the Icacos Field, and at end 2010 was awaiting the Minister of Energy's signature to the new production licence. Subsequently, PwC has announced that the Primera interests were to be sold in an all shares transaction with Touchstone Exploration Inc (Touchstone). At the date of this report LGO is now in discussions with Touchstone.
LGO is also engaged in commercial negotiations with a number of other operators and lease owners in the Southern Basin of Trinidad with a view to farming in or otherwise gaining entry to new field redevelopment or exploitation projects to increase the Company's footprint in Trinidad. Announcements on these negotiations are expected in the second half of 2011. The Company has also signed, during second quarter 2011, various new land leases to acquire the exclusive petroleum rights to land in the Cedros Peninisula with a view to applying for a Private Petroleum Licence in due course.
Total net beneficial production from the Icacos oilfield during the reporting period was 6,707 bbls of oil.
MALTA:
LGO retains 10% in Area 4 (comprising Blocks 4, 5, 6 and 7) of Southern Offshore Malta, operated by Mediterranean Oil & Gas ("MOG") who retain the balance of the interest. The Area is governed by a Production Sharing Contract (PSC) with the Maltese Ministry of Natural Resources with a commitment to drill by July 2011.
Four prospects and five leads on the 5,700 sq km PSC Area have been delineated, with the total most likely hydrocarbon potential of the PSC Area estimated at gross 5 billion barrels of oil in place with resultant total most likely case prospective recoverable oil resources of 1.475 mmbo gross. These leads, first defined in 2009, have not been materially changed by ongoing technical work during the reporting period.
In early 2011 MOG advised LGO and the Maltese Government that it would seek an extension of the exploration period so as to conduct further work in the PSC prior to making a commitment to drill. At the date of this report LGO has approved an 18 month extension 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 is to be acquired in 2011 to complete the pre-drill technical evaluation.
Neil Ritson
Chief Executive Officer
3 June 2011
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 SPE 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 2010. 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
2010 continued to mark the turning point in the evolution of Leni Gas and Oil plc. Encouraging production arose from further developing our Spanish, US and Trinidad operations. The financial statements presented herein do not as yet represent this real shift in direction but the immediate years ahead should reflect this.
LGO is primarily a development business with programs in place to monetise the Company's interests in various oil and gas operations. Expectations are forecast of a significant increase in production volumes and therefore revenue in the next few years. The results for the year reflect this status and the Group recorded a gross profit of £0.52 million (2009: £1.05 million) and an operating loss after tax of £10.29 million (2009: £2.06 million) for the period ended 31 December 2010 mainly attributable to an impairment charge of £6.9 million (2009: £1.67 million) relating to the provision for write-down of the Company's investments in Gulf of Mexico (2009: Hungary investments) and £0.61 million (2009:£0.17 million) for non-cash share based payments.
Revenue in the period of £2.26 million (2009: £2.13 million) arose from oil and gas sales from operations.
Cash flow
Cash flow from operating activities after movements in working capital amounted to £1.50 million (2009: £1.18 million). Net cash inflow from financing activities was £6.99 million (2009: £0.45million). Net cash outflow from investing activities was £1.96 million (2009: £1.80 million) of which £1.98 million (2009: £1.86million) was incurred on capital expenditure relating to field development and exploration in all countries of operation.
Net cash position
Net cash at 31 December 2010 was £3.85 million. (2009: £0.23 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
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
bwpd = barrels of water per day
bfpd = barrel of fluid per day
CCS = carbon capture and sequestration
Contingent Resources = those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from known accumulations but which are not currently considered to be commercially recoverable.
CO2 = carbon dioxide
EOR = enhanced oil recovery
GIIP = Gas Initially In Place
GoM = US Gulf of Mexico
HSE = Health Safety and Environment
m = thousand
mm = million
mmscf = million standard cubic feet of gas per day
mmscfd = mmscf per day
Prospective Resources = those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from undiscovered accumulations.
Proved Reserves = the estimated volumes of crude oil, condensate, natural gas and natural gas liquids which, based upon geologic and engineering data, are reasonably certain to be commercially recovered from known reservoirs under existing economic and political/regulatory conditions and using conventional or existing equipment and operating methods
PSC = Production Sharing Contract
Sq km = square kilometres
STOIIP = Stock Tank Oil Initially In Place
All figures are net LGO unless otherwise stated
All reserves and resources definitions used are per the Society of Petroleum Engineers' Petroleum Resources Management System.
Financial Statements
GROUP STATEMENT OF COMPREHENSIVE INCOMEFOR THE YEAR ENDED 31 DECEMBER 2010
Year ended31 December 2010 | Year ended31 December 2009 | ||
Notes | £ 000's | £ 000's | |
Revenue | 2 | 2,264 | 2,133 |
Cost of sales | (1,741) | (1,081) | |
Gross profit | 523 | 1,052 | |
Administrative expenses | 3 | (1,473) | (897) |
Amortisation and depreciation | 3 | (1,843) | (91) |
Share based payments | 20 | (610) | (169) |
Loss from operations | (3,403) | (105) | |
Impairment charge | 12 | (6,904) | (1,670) |
Share of associate's results | 13 | - | (344) |
Finance revenue | 9 | 15 | 66 |
Loss before taxation | (10,292) | (2,053) | |
Income tax expense | 5 | 5 | (6) |
Loss for the year | (10,287) | (2,059) | |
Other comprehensive income | |||
Exchange differences on translation of foreign operations | (113) | (151) | |
Other comprehensive income for the year net of taxation | (113) | (151) | |
Total comprehensive income for the year attributable to equity holders of the parent | (10,400) | (2,210) | |
Loss per share (pence) | |||
Basic | 8 | (1.51) | (0.34) |
Diluted | 8 | (1.51) | (0.34) |
All of the operations are considered to be continuing. |
GROUP STATEMENT OF FINANCIAL POSITIONAS AT 31 DECEMBER 2010
As at 31 December 2010 | As at 31 December 2009 | ||
Note | £ 000's | £ 000's | |
Assets | |||
Non-current assets | |||
Property, plant and equipment | 11 | 303 | 386 |
Intangible assets | 10 | 15,125 | 7,689 |
Interest in associate | 13 | - | 14,072 |
Total non-current assets | 15,428 | 22,147 | |
Current assets | |||
Inventories | 16 | 96 | 168 |
Trade and other receivables | 15 | 446 | 922 |
Cash and cash equivalents | 3,852 | 230 | |
Total current assets | 4,394 | 1,320 | |
Total assets | 19,822 | 23,467 | |
Liabilities | |||
Current liabilities | |||
Trade and other payables | 17 | (555) | (1,358) |
Borrowings | 18 | - | (453) |
Total current liabilities | (555) | (1,811) | |
Non-current liabilities | |||
Provisions | 19 | (817) | (858) |
Total non-current liabilities | (817) | (858) | |
Total liabilities | (1,372) | (2,669) | |
Net assets | 18,450 | 20,798 | |
Shareholders' equity | |||
Called-up share capital | 20 | 460 | 304 |
Share premium | 30,192 | 22,663 | |
Share based payments reserve | 21 | 830 | 463 |
Retained earnings | (13,262) | (2,975) | |
Foreign exchange reserve | 230 | 343 | |
Total equity attributable to equity holders of the parent | 18,450 | 20,798 | |
These financial statements were approved by the Board of Directors on 3 June 2011 and signed on its behalf by: | |||
David Lenigas | Donald Strang | ||
Executive Chairman | Finance Director | ||
COMPANY STATEMENT OF FINANCIAL POSITIONAS AT 31 DECEMBER 2010
As at 31 December 2010 | As at 31 December 2009 | ||
Note | £ 000's | £ 000's | |
Assets | |||
Non-current assets | |||
Investment in subsidiaries | 14 | 2 | 2 |
Trade and other receivables | 15 | 20,824 | 19,291 |
Total non current assets | 20,826 | 19,293 | |
Current assets | |||
Trade and other receivables | 15 | 2,007 | 1,048 |
Cash and cash equivalents | 3,744 | 26 | |
Total current assets | 5,751 | 1,074 | |
Total assets | 26,577 | 20,367 | |
Liabilities | |||
Current liabilities | |||
Trade and other payables | 17 | (297) | (391) |
Borrowings | 18 | - | (453) |
Total liabilities | (297) | (844) | |
Net assets | 26,280 | 19,523 | |
Shareholders' equity | |||
Called-up share capital | 20 | 460 | 304 |
Share premium | 30,192 | 22,663 | |
Share based payments reserve | 21 | 830 | 463 |
Retained earnings | 26 | (5,202) | (3,907) |
Total equity attributable to equity holders of the parent | 26,280 | 19,523 | |
These financial statements were approved by the Board of Directors on 3 June 2011 and signed on its behalf by: | |||
David Lenigas | Donald Strang | ||
Executive Chairman | Finance Director | ||
GROUP STATEMENT OF CASH FLOWSFOR THE YEAR ENDED 31 DECEMBER 2010
Year ended 31 December 2010 | Year ended 31 December 2009 | |
£ 000's | £ 000's | |
Cash outflow from operating activities | ||
Operating (loss) | (3,403) | (105) |
Decrease in trade and other receivables | 476 | 207 |
(Decrease)/increase in trade and other payables | (803) | 864 |
Decrease/(increase) in inventories | 72 | (39) |
Depreciation | 66 | 60 |
Amortisation | 1,777 | 31 |
Share based payments | 610 | 169 |
Income tax received/(paid) | 6 | (6) |
Net cash (outflow)/inflow from operating activities | (1,499) | 1,181 |
Cash flows from investing activities | ||
Interest received | 15 | 66 |
Payments to acquire intangible assets | (1,978) | (1,857) |
Payments to acquire tangible assets | - | (11) |
Net cash outflow from investing activities | (1,963) | (1,802) |
Cash flows from financing activities | ||
Issue of ordinary share capital | 7,801 | - |
Share issue costs | (359) | - |
Proceeds from borrowings | (453) | 453 |
Net cash inflow from financing activities | 6,989 | 453 |
Net increase/(decrease) in cash and cash equivalents | 3,527 | (168) |
Foreign exchange differences on translation | 95 | (173) |
Cash and cash equivalents at beginning of period | 230 | 571 |
Cash and cash equivalents at end of period | 3,852 | 230 |
COMPANY STATEMENT OF CASH FLOWSFOR THE YEAR ENDED 31 DECEMBER 2010
Year ended31 December 2010 | Year ended31 December 2009 | |
£ 000's | £ 000's | |
Cash outflow from operating activities | ||
Operating (loss) | (1,316) | (727) |
(Increase) in trade and other receivables | (959) | (467) |
(Decrease)/increase in trade and other payables | (94) | 214 |
Share based payments expensed | 610 | 169 |
Income tax received/(paid) | 6 | (6) |
Net cash outflow from operating activities | (1,753) | (817) |
Cash flows from investing activities | ||
Interest received | 15 | 66 |
Loans granted to subsidiaries | (1,533) | (106) |
Payments to acquire subsidiaries | - | (1) |
Net cash outflow from investing activities | (1,518) | (41) |
Cash flows from financing activities | ||
Issue of ordinary share capital | 7,801 | - |
Share issue costs | (359) | - |
Proceeds from borrowings | (453) | 453 |
Net cash inflow from financing activities | 6,989 | 453 |
Net increase/(decrease) in cash and cash equivalents | 3,718 | (405) |
Cash and cash equivalents at beginning of period | 26 | 431 |
Cash and cash equivalents at end of period | 3,744 | 26 |
STATEMENT OF CHANGES IN EQUITYFOR THE YEAR ENDED 31 DECEMBER 2010
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 2008 | 304 | 22,663 | 294 | (916) | 494 | 22,839 |
Loss for the year | - | - | - | (2,059) | - | (2,059) |
Currency translation differences | - | - | - | - | (151) | (151) |
Total comprehensive income | - | - | - | (2,059) | (151) | (2,210) |
Share capital issued | - | - | - | - | - | - |
Cost of share issue | - | - | - | - | - | - |
Share based payments | - | - | 169 | - | - | 169 |
As at 31 December 2009 | 304 | 22,663 | 463 | (2,975) | 343 | 20,798 |
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 |
As at 31 December 2010 | 460 | 30,192 | 830 | (13,262) | 230 | 18,450 |
Company | ||||||
As at 31 December 2008 | 304 | 22,663 | 294 | (1,570) | - | 21,691 |
Loss for the year | - | - | - | (2,337) | - | (2,337) |
Total comprehensive income | - | - | - | (2,337) | - | (2,337) |
Share capital issued | - | - | - | - | - | - |
Cost of share issue | - | - | - | - | - | - |
Share based payments | - | - | 169 | - | - | 169 |
As at 31 December 2009 | 304 | 22,663 | 463 | (3,907) | - | 19,523 |
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 |
As at 31 December 2010 | 460 | 30,192 | 830 | (5,202) | - | 26,280 |
NOTES TO THE FINANCIAL STATEMENTS FOR THE YEAR ENDED 31 DECEMBER 2010
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 2010 were authorised for issue by the Board on 3 June 2011 and the balance sheets signed on the Board's behalf by Mr. David Lenigas and Mr. Donald Strang | |
1.02 | Statement of compliance with IFRS |
The Group's financial statements have been prepared in accordance with International Financial Reporting Standards (IFRS). The Company's financial statements have been prepared in accordance with IFRS as adopted by the European Union and as applied in accordance with the provisions of the Companies Act 2006. The principal accounting policies adopted by the Group and Company are set out below.
As at the date of authorisation of these financial statements, there were Standards and Interpretations that were in issue but are not yet effective and have not been applied in these financial statements. The Directors anticipate that the adoption of these Standards and Interpretations in future periods will have no material impact on the financial statements of the group or company, except for additional disclosures when the relevant Standards come into effect | |
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'.
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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. (Note: the company currently does not have any borrowings attracting interest) | |
1.18 | Provisions |
Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. | |
When the Group expects some or all of a provision to be reimbursed, for example under an insurance contract, the reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision is presented in the income statement net of any reimbursement. |
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. | |
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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 | 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. | |
1.23 | 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. | |
1.24 | Share issue expenses and share premium account |
Costs of share issues are written off against the premium arising on the issues of share capital. |
1.25 | 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. | |
1.26 | 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 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 | 644 | - | 103 | 845 | |
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) | |
Corporate | Holding | Operating | Operating | Operating | Total | ||
Year ended 31 December 2009 | UK | Cyprus | Spain | Trinidad | US | ||
£'000 | £'000 | £'000 | £'000 | £'000 | £'000 | ||
Operating loss by geographical area | |||||||
Revenue | - | - | 2,133 | - | - | 2,133 | |
Operating profit/(loss) | (667) | - | 562 | - | - | (105) | |
Impairment charge | - | (1,670) | - | - | - | (1,670) | |
Share of associates' result | - | (344) | - | - | - | (344) | |
Finance revenue | 66 | - | - | - | - | 66 | |
Profit/(loss) before taxation | (601) | (2,014) | 562 | - | - | (2,053) | |
Other information | |||||||
Depreciation and amortisation | - | - | 91 | - | - | 91 | |
Capital additions | - | 79 | 1,789 | - | - | 1,868 | |
- | - | ||||||
Segment assets | - | 15,499 | 6,638 | - | - | 22,137 | |
Financial assets | 507 | 189 | 394 | - | - | 1,090 | |
Cash | 26 | - | 204 | - | - | 230 | |
Consolidated total assets | 533 | 15,688 | 7,236 | - | - | 23,457 | |
Segment liabilities | - | - | - | - | - | - | |
Trade and other payables | (845) | (5) | (961) | - | - | (1,811) | |
Provisions | - | - | (858) | - | - | (858) | |
Consolidated total liabilities | (845) | (5) | (1,819) | - | - | (2,669) |
3 | Operating loss | 2010 | 2009 |
£ 000's | £ 000's | ||
Operating loss is arrived at after charging: | |||
Auditors' remuneration - audit | 19 | 19 | |
Auditors' remuneration - non audit services | - | - | |
Directors' emoluments - fees and salaries | 131 | 120 | |
Directors' emoluments - share based payments and options | 505 | 120 | |
Depreciation | 66 | 60 | |
Amortisation | 1,777 | 31 | |
Auditors remuneration for audit services above includes £4,291 (2009: £4,012) charges by MGI Gregoriou & Co Certified Public Accountants (Cyprus) relating to the audit of the subsidiary companies. | |||
4 | Employee information (excluding directors') | 2010 | 2009 |
Staff costs comprised: | £ 000's | £ 000's | |
Wages and salaries | 674 | 630 | |
Social security contributions | 176 | 155 | |
Total staff costs | 850 | 785 | |
The average number of employees on a full time equivalent basis during the year was as follows: | |||
Number | Number | ||
Administration | 5 | 3 | |
Operations | 14 | 11 | |
Total | 19 | 14 | |
5 | Taxation | 2010 | 2009 |
Analysis of (credit)/charge in period | £ 000's | £ 000's | |
Tax on ordinary activities | (5) | 6 | |
No taxation has been provided due to losses in the period | |||
Factors affecting the tax charge for the period: | |||
Loss on ordinary activities before tax | (10,287) | (2,059) | |
Standard rate of corporation tax in the UK | 28% | 28% | |
Loss on ordinary activities multiplied by the standard rate of corporation tax | (2,880) | (577) | |
Effects of: | |||
Non deductible expenses | - | - | |
Withholding tax on overseas interest | (5) | 6 | |
Future tax benefit not brought to account | (2,880) | 577 | |
Current tax charge for period | (5) | 6 | |
No deferred tax asset has been recognised because there is uncertainty of the timing of suitable future profits against which they can be recovered.
There are approximately £1,977,000 (2009: £580,000) 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 (2009: nil). |
7 | Directors' emoluments | ||||
2010 | 2009 | ||||
£ 000's | £ 000's | ||||
Directors' remuneration | 1,176 | 772 | |||
Directors Fees | Consultancy Fees | Share based payments | Total | ||
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 | |
67 | 604 | 505 | 1,176 | ||
2009 | |||||
Executive Directors | |||||
David Lenigas | 12 | 240 | - | 252 | |
Neil Ritson | - | - | - | - | |
Fraser Pritchard | 12 | 160 | 24 | 196 | |
Donald Strang | 12 | 156 | 72 | 240 | |
Jeremy Edelman | 12 | 48 | 24 | 84 | |
48 | 604 | 120 | 772 | ||
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 During the period a total of £540,000 (2009: £532,000) of consultancy fees, payable by an overseas subsidiary, were accrued to directors (as detailed in Note 24) and were capitalised in accordance with the Group's accounting policies. | |||||
8 | Loss per share | ||
The calculation of loss per share is based on the loss after taxation divided by the weighted average number of share in issue during the period: | |||
2010 | 2009 | ||
Net loss after taxation (£000's) | (10,287) | (2,059) | |
Weighted average number of ordinary shares used in calculating basic loss per share (millions) | 683.2 | 608.3 | |
Weighted average number of ordinary shares used in calculating diluted loss per share (millions) | 822.1 | 612.6 | |
Basic loss per share (expressed in pence) | (1.51) | (0.34) | |
Diluted loss per share (expressed in pence) | (1.51) | (0.34) | |
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 | 2010 | 2009 |
£ 000's | £ 000's | ||
Bank interest receivable | 2 | 1 | |
Interest income on loan to associate | 13 | 65 | |
15 | 66 |
10 | Intangible assets | 2009 | ||
Group | £ 000's | |||
Cost | ||||
As at 1 January 2010 | 9,408 | |||
Additions | 17,108 | |||
Disposal | (1,670) | |||
Foreign exchange difference on translation | (1,061) | |||
As at 31 December 2010 | 23,785 | |||
Amortisation | ||||
As at 1 January 2010 | 1,719 | |||
Amortisation | 1,777 | |||
Disposal | (1,670) | |||
Impairment charge | 6,904 | |||
Foreign exchange difference on translation | (70) | |||
As at 31 December 2010 | 8,660 | |||
Net book value | ||||
As at 31 December 2010 | 15,125 | |||
As at 31 December 2009 | 7,689 | |||
2010 | 2009 | ||
£ 000's | £ 000's | ||
The net book value is analysed as follows: | |||
Oil and gas properties | 12,818 | 5,402 | |
Deferred exploration expenditure | 1,498 | 1,436 | |
Decommissioning costs | 809 | 851 | |
15,125 | 7,689 | ||
Impairment review | |||
At 31 December 2010, the Directors have 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. | |||
11 | Property, plant and equipment | 2010 | |
Group | £ 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 | ||
As at 31 December 2010 | 303 | ||
As at 31 December 2009 | 386 | ||
Impairment review | |||
At 31 December 2010, the Directors have carried out an impairment review and confirmed that no provision is currently required. | |||
12 | Impairment charge |
The Board of Directors undertook an impairment review of the Group's assets as at 31 December 2010 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 2010 by country. Due to ongoing operational issues at the Eugene Island Field in the Gulf of Mexico, which has resulted in lower monthly production and the ongoing financial concerns surrounding the Field operator (Leed Petroleum Plc), the Directors felt it was prudent to reduce the carrying value of the Eugene Island Field asset to a level which better reflects the amount able to be amortised fully over the Group's share of current remaining oil and gas reserves. Subsequently the value of the Group's investment in the Eugene Island Field has been written down by £6.9 million to approximately £6.2 million.
The Directors are of the opinion that after this impairment, the carrying values of the tangible and intangible assets in relation to the Group's projects are stated at a fair value. The carrying values will be subject to an ongoing review as the Group continues to develop each project in the future.
|
13 | Interest in associate | ||
Group | £ 000's | ||
Cost | |||
As at 1 January 2010 | 14,072 | ||
Additions | - | ||
Disposal | (14,072) | ||
Share of associate's loss for the period | - | ||
As at 31 December 2010 | - | ||
On 20 January 2010, the Group completed the conversion agreement to transfer its shareholding in Byron Energy Limited (Byron) to a direct working interest ownership of its US Gulf of Mexico and Gulf Coast assets. The Group's 28.94% shareholding was bought back by Byron in consideration for the transfer of part of Byron's direct working interest in the Eugene Island Blocks (as detailed in the operations review), to Leni Gas & Oil US Inc.. The effective consideration for the share buyback was the transfer by Byron of part of their direct working interest in the Eugene Island Blocks, and repayment of the outstanding loan from the Group to Byron, leaving a nil gain/loss on disposal of the associate interest. | |||
14 | Investment in subsidiaries | 2010 | ||||
Shares in Group undertaking | £ 000's | |||||
Company | ||||||
Cost | ||||||
As at 1 January 2010 | 2 | |||||
Additions | - | |||||
As at 31 December 2010 | 2 | |||||
The parent company of the Group holds more than 20% of the share capital of the following companies: | ||||||
Company | Country of Registration | Proportion held | Nature of business | |||
Direct | ||||||
Leni Gas & Oil Holdings Ltd | Cyprus | 100% | Holding Company | |||
Leni Trinidad Ltd | Trinidad & Tobago | 100% | Investment Company | |||
Indirect | ||||||
Via Leni Gas & Oil Holdings Ltd | ||||||
Leni Gas & Oil Investments Ltd | Cyprus | 100% | Investment Company | |||
Leni Investments Cps Ltd | Cyprus | 100% | Investment Company | |||
Leni Investments Byron Ltd | Cyprus | 100% | Investment Company | |||
Leni Investments Trinidad Ltd | Cyprus | 100% | Investment Company | |||
Via Leni Investments Cps Ltd | ||||||
Compania Petrolifera de Sedano S.L. | Spain | 100% | Oil and Gas Production and Exploration Company | |||
Via Leni Investments Byron Ltd | ||||||
Leni Gas and Oil US Inc. | United States | 100% | Oil and Gas Production and Exploration Company | |||
15 | Trade and other receivables | 2010 | 2009 | ||
Group | Company | Group | Company | ||
£ 000's | £ 000's | £ 000's | £ 000's | ||
Current trade and other receivables | |||||
Trade receivables | 296 | - | 210 | - | |
VAT receivable | 14 | 14 | 12 | 12 | |
Other receivables | 1 | 1,970 | 482 | 1,007 | |
Prepayments | 135 | 23 | 218 | 29 | |
Total | 446 | 2,007 | 922 | 1,048 | |
Non current trade and other receivables | |||||
Loans due from subsidiaries | - | 20,824 | - | 19,291 | |
Total | - | 20,824 | - | 19,291 | |
The loans due from subsidiaries are interest free and have no fixed repayment date. | |||||
16 | Inventories | 2010 | 2009 | ||
Group | Company | Group | Company | ||
£ 000's | £ 000's | £ 000's | £ 000's | ||
Inventories - Crude Oil | 96 | - | 168 | - | |
17 | Trade and other payables | 2010 | 2009 | ||
Group | Company | Group | Company | ||
£ 000's | £ 000's | £ 000's | £ 000's | ||
Current trade and other payables | |||||
Trade Payables | 488 | 254 | 520 | 240 | |
Accruals | 67 | 43 | 838 | 151 | |
Total | 555 | 297 | 1,358 | 391 | |
18 | Borrowings | 2010 | 2009 | ||
Group | Company | Group | Company | ||
£ 000's | £ 000's | £ 000's | £ 000's | ||
Current | |||||
Loans - other (unsecured) | - | - | 333 | 333 | |
Loans from Directors (unsecured) | - | - | 120 | 120 | |
- | - | 453 | 453 | ||
The loans due to directors, and other parties were interest free and had no fixed repayment date. The carrying amounts of short-term borrowings approximate their fair value, and are all denominated in pounds sterling. | |||||
19 | Provisions | 2010 | 2009 | ||
Provision for decommissioning costs | Group | Company | Group | Company | |
£ 000's | £ 000's | £ 000's | £ 000's | ||
At 1 January | 858 | - | 925 | - | |
Foreign exchange difference on translation | (41) | - | (67) | - | |
At 31 December | 817 | - | 858 | - | |
These costs relate to the estimated liability for removal of Spanish production facilities and site restoration at the end of the production life of the facilities. | |||||
20 | Share capital | |||
Authorised | ||||
The Companies Act 2006 abolishes the requirement for a company to have an authorised share capital. As a result, the Company's Articles of Association were amended at the AGM on 7 July 2010 to remove all reference to an authorised share capital.
The Directors of the Company continue to be limited as to the number of shares they can allot at any time and remain subject to the allotment authority granted by the shareholders pursuant to section 551 of the Companies Act 2006 | ||||
Called up, allotted, issued and fully paid | Number of shares | Nominal value (£000's) | ||
As at 1 January 2009 | 608,254,965 | 304 | ||
No shares issued in the year | - | - | ||
As at 31 December 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 | ||
During the year 311 million shares were issued (2009: nil). | ||||
Total share options in issue | ||||
During the year 25 million options were issued (2009: nil). | ||||
As at 31 December 2010 the options in issue were: | ||||
Exercise Price | Expiry Date | Options in Issue 31 December 2010 | ||
3p | 16 March 2012 | 16,000,000 | ||
2.5p | 9 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 | ||
57,300,000 | ||||
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 (2009: nil) | ||||
As at 31 December 2010 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. (2009: nil) | ||||
21 | Share based payment arrangements | ||||||||
Share options | |||||||||
During 2008, the Company established an employee share option plan to enable the issue of options as part of remuneration of key management personnel and Directors to enable the purchase of shares in the entity. Options were granted under the plan for no consideration. Options were granted for a 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.
| |||||||||
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 | 3.20 | 1.57 | ||
Neil Ritson | 19 November 2010 | 19 November 2010 | 5,000,000 | 4 | 18 November 2013 | 3.20 | 1.32 | ||
Neil Ritson | 19 November 2010 | 19 November 2010 | 5,000,000 | 5 | 18 November 2013 | 3.20 | 1.13 | ||
Neil Ritson | 19 November 2010 | 19 November 2010 | 5,000,000 | 6 | 18 November 2013 | 3.20 | 0.98 | ||
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 | 41,300,000 | ||||||||
The fair value of the options vested during the period was £367,331 (2009: £169,000). The assessed fair value at grant date is determined using the Black-Scholes Model that takes into account the exercise price, the term of the option, the share price at grant date, the expected price volatility of the underlying share, the expected dividend yield and the risk-free interest rate for the term of the option.
| |||||||||
The following table lists the inputs to the model used for the period ended 31 December 2010:
| |||||||||
19 November 2010 issue | |||||||||
Dividend Yield (%) | - | ||||||||
Expected Volatility (%) | 70 | ||||||||
Risk-free interest rate (%) | 2 | ||||||||
Share price at grant date (pence) | 3.2 | ||||||||
The expected volatility reflects the assumption that the historical volatility is indicative of future trends, which may, not necessarily be the actual outcome. A discount factor of 80% has been applied to the value of the options issued to staff.
| |||||||||
22 | Financial instruments | ||||||||||
The Group uses financial instruments comprising cash, and debtors/creditors that arise from its operations. The Group holds cash as a liquid resource to fund the obligations of the Group. The Group's cash balances are predominantly held in Sterling. The Group's strategy for managing cash is to maximise interest income whilst ensuring its availability to match the profile of the Group's expenditure. This is achieved by regular monitoring of interest rates and monthly review of expenditure forecasts.
The Company has a policy of not hedging and therefore takes market rates in respect of foreign exchange risk; however it does review its currency exposures on an ad hoc basis. Currency exposures relating to monetary assets held by foreign operations are included within the foreign exchange reserve in the Group Balance Sheet.
The Group considers the credit ratings of banks in which it holds funds in order to reduce exposure to credit risk.
To date the Group has relied upon equity funding to finance operations. The Directors are confident that adequate cash resources exist to finance operations to commercial exploitation but controls over expenditure are carefully managed.
The net fair value of financial assets and liabilities approximates the carrying values disclosed in the financial statements. The currency and interest rate profile of the financial assets is as follows:
| |||||||||||
Cash and short term deposits | 2010 | 2009 | |||||||||
£ 000's | £ 000's | ||||||||||
Sterling | 3,744 | 26 | |||||||||
Euros | 22 | 204 | |||||||||
US Dollars | 33 | - | |||||||||
Trinidad Dollars | 53 | - | |||||||||
3,852 | 230 | ||||||||||
The financial assets comprise cash balances in interest earning bank accounts at call. The financial assets in Sterling currently earn interest at the base rate set by the Bank of England less 0.15%
| |||||||||||
Foreign currency risk | |||||||||||
The following table details the Group's sensitivity to a 10% increase and decrease in the Pound Sterling against the relevant foreign currencies of Euro, US Dollar. 10% represents management's assessment of the reasonably possible change in foreign exchange rates.
The sensitivity analysis includes only outstanding foreign currency denominated investments and other financial assets and liabilities and adjusts their translation at the period end for a 10% change in foreign currency rates. The following table sets out the potential exposure, where the 10% increase or decrease refers to a strengthening or weakening of the Pound Sterling:
| |||||||||||
Profit or loss sensitivity | Equity sensitivity | ||||||||||
10% increase | 10% decrease | 10% increase | 10% decrease | ||||||||
$ 000's | $ 000's | $ 000's | $ 000's | ||||||||
Euro | (67) | 67 | (59) | 59 | |||||||
US Dollar | (834) | 834 | (833) | 833 | |||||||
Trinidad Dollar | (2) | 2 | (2) | 2 | |||||||
(903) | 903 | (894) | 894 | ||||||||
Rates of exchange to £1 used in the financial statements were as follows: | |||||||||||
| As at 31 December 2010 | Average for the relevant consolidated period to 31 December 2010 | As at 31 December 2009 | Average for the relevant consolidated period to 31 December 2009 | |||||||
Euro | 1.1674 | 1.1651 | 1.1113 | 1.1215 | |||||||
US Dollar | 1.5470 | 1.5448 | 1.5928 | 1.5597 | |||||||
Trinidad Dollar | 9.9900 | 9.9619 | - | - | |||||||
23 | Commitments and Contingencies |
As at 31 December 2010, the Company had entered into the following material commitments: | |
The Company signed a deed of Amendment and Assignment Agreement with Malta Oil Pty Limited, a subsidiary of Mediterranean Oil and Gas plc in July 2008 to acquire 10% participating interest in a production sharing contract. Minimum expenditure for the Company under this agreement is approximately US$ 500,000. To 31 December 2010, the Group has expensed US$162,000 in relation to this agreement. | |
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. |
24 | Related party transactions | ||
Transactions between the Company and its subsidiaries, which are related parties, have been eliminated on consolidation and are not disclosed in this note. Transactions between other related parties are discussed below.
During the period, the Company accrued the following consultancy fees to the Company's directors for work performed in relation to an overseas subsidiary. These fees have been recharged to this subsidiary as follows : (i) £228,000 to David Lenigas (2009: £228,000), (ii) £156,000 to Donald Strang (2009: £144,000), (iii) £156,000 to Fraser Pritchard (2009:£160,000). (iv) Total accrued £ 540,000 (2009:£532,000).
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. | |||
2010 | 2009 | ||
£ 000's | £ 000's | ||
Short-term employee benefits | 438 | 294 | |
Share-based payments | 610 | 133 | |
1,048 | 424 | ||
25 | Post balance sheet events |
On 3 February 2011 Steve Horton was appointed as a Non-Executive Director, and was granted 5 million share options, with an exercise price of 5p per share, expiring on 31 January 2014.
On 5 April 2011, the current operator of the Eugene Island Field, Leed Petroleum plc ("Leed"), announced suspension of production in the Eugene Field in Gulf of Mexico, ceasing temporarily the Group's royalty revenue from production therein. On 23 May 2011, the Company announced Leed had sold all of its Gulf of Mexico properties and that the new operator for the Eugene Island Field would be Marlin Energy LLC, a private oil and gas company based in Lafayette, Louisiana. Resumption of production operations was anticipated for June 2011.
On 28 April 2011, the Company issued 15 million share options to Garry Stoker, with exercise prices from 3p to 6p per share, expiring on 3 May 2014.
On 28 April 2011, the Company announced that Fraser Pritchard would be resigning as a director of the Company at the next AGM.
|
26 | Profit and loss account of the parent company |
As permitted by section 408 of the Companies Act 2006, the profit and loss account of the parent company has not been separately presented in these accounts. The parent company loss for the period was £1.295 million (2009: £2.337 million). |
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 2010 or 2009. The financial information for the year ended 31 December 2009 is derived from the statutory accounts for that year. The audit of statutory accounts for the year ended 31 December 2010 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.
Related Shares:
CERP.L