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Share Name | Share Symbol | Market | Type |
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Nevada Organic Phosphate Inc | CSE:NOP | CSE | Common Stock |
Price Change | % Change | Share Price | Bid Price | Offer Price | High Price | Low Price | Open Price | Shares Traded | Last Trade | |
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0.00 | 0.00% | 0.06 | 0.05 | 0.06 | 0 | 09:50:10 |
RNS Number:1096L Northern Petroleum PLC 15 May 2003 Embargoed: 0700 hrs 15 May 2003 Northern Petroleum Plc ("Northern" or the "Company") Final Audited Results for the Year Ended 31 December 2002 HIGHLIGHTS * PROFIT PER SHARE OF 0.15 PENCE AFTER WRITE OFFS * PROFITABLE SALE OF IRISH INVESTMENTS * IMMEDIATE PAYBACK ON INVESTMENT IN SPANISH PRODUCTION * STRONG CASH POSITION * 3.9 MILLION BARRELS RECOVERABLE PROBABLE RESERVES IN UK * ALL INVESTMENTS NOW UNDER THE COMPANY'S OWN OPERATIONAL CONTROL * NEW LICENCES AWARDED Richard Latham, Chairman of Northern Petroleum Plc, commented, "This has been a year of significant progress. We achieved the profitable sale of our Irish investments and a six month payback on our investment in the Ayoluengo oil field. We have doubled to a 40% interest our position in licence PEDL 113, on the Isle Of Wight, where we have now established 3.9 million barrels of recoverable probable oil reserves net to the Company. It is, in my view, of great importance that Northern has now achieved operational control over all its investments. This progress coupled with a strong cash position affords me a great deal of confidence in Northern Petroleum going forward." For Further Information Please Contact: Richard Latham Chairman Northern Petroleum Plc Tel: +44 (0) 20 7743 6080 Derek Musgrove Managing Director Northern Petroleum Plc Tel: +44 (0) 20 7743 6080 Chris Roberts Ben Simons Hansard Communications Tel: +44 (0) 20 7245 1100 Chairman's Statement I report a profit of 0.15p per share reflecting, after write offs, the profitable sale of our Irish investments and the commencement of profitable operations in Spain. I also report the establishment of almost four million barrels, verified by independent consultants, of probable recoverable oil reserves on the Isle of Wight. This has been a year of significant progress. We achieved the profitable sale of our Irish investments and a six-month payback on our investment in the Ayoluengo oil field. We have doubled to a 40% interest our position in licence PEDL 113, on the Isle Of Wight, where we have now established 3.9 million barrels of recoverable probable oil reserves net to the Company. It is, in my view, of great importance that Northern has now achieved operational control over all its investments. This progress coupled with a strong cash position affords me a great deal of confidence in Northern Petroleum going forward. The successful appraisal drilling in 2001 of the Seven Heads Gas Field was followed in 2002 by the development of economically attractive plans for putting the field into production. In July 2002 we sold our interest in both the Seven Heads and Galley Head gas fields for #2 million in cash and 294,118 ordinary shares of Ramco Energy plc. Your Board took this action as we accepted the paramount importance of having the major part of our investments under our own management control. The sale also released funds which could be redeployed to add value in the short term rather than be locked into a project to which little significant value could be added by us until first production scheduled for late 2003. The Seven Heads gas field is forecast to supply some 10% of Irish requirements. It remains a good project and it was particularly pleasing to read that the first development well tested 34.3 mmscfd, a result substantially better than expected. We are maintaining through our holding of Ramco Energy plc shares virtually the same exposure as originally invested in this project and are confident that we will benefit as the market becomes aware of the positive achievements of the project. Gary Moore joined the Board during the year as a result of this transaction and resigned in May 2003 to pursue other interests. We hope these will prove as successful for him as Seven Heads and thank him for his considerable contribution to the Company. In May 2002 we purchased from Repsol/YPF a 45% interest in the La Lora licence in Northern Spain which includes the Ayoluengo oil field. We also arranged with the remaining partners to be appointed as Operator to manage the field. It is pleasing to report that, with the improved oil prices and the uncontrolled delays in receiving approvals from the authorities in Madrid, by the time the transaction became unconditional on December 12th 2002, sufficient net revenues had already accrued since July 1st , to cover more than the purchase price of $112,500. Whilst I would wish to show an operating profit for the Ayoluengo field of #68,691 for the period 1st July to 31st December 2002 I am advised that this would not conform with Financial Reporting Standards 5 and 7. As a consequence, and you are referred to the Finance Report, the benefits prior to December 12th are shown as negative goodwill, a result of acquiring assets for less than they are now worth. It is our initial intention to increase profits from Ayoluengo by a programme of cost reduction, down-hole clean up, restoration and further lateral drilling into as yet un-drained areas of the reservoir. The first phase has already begun with initially encouraging results. In the longer term we are working to confirm drilling targets below and on the flanks of the current area in production. I am reminded of the adage that the best place to find oil is in the shadow of an oil field. On another nearby licence we are developing plans to drill the Hontomin-4 appraisal well combined with a deeper test to benefit from the drilling and testing in 1991-1992 of Hontomin-2 which tested up to 200 bopd of oil, but with water. This is viewed as a sufficiently low-risk project to meet our business strategy criteria. Unlike the previous licensee we will now have the added benefit of being able to test and produce using the oil handling and water disposal facilities at Ayoluengo only 20km away. Another well being planned is Huidobro-3 to attempt to produce oil from the Cretaceous formation from which Chevron tested oil in 1963. It is also intended that the structure will be tested at the deeper Middle Jurassic horizon in which reportedly oil was logged at greater depths in the nearby Lora-1 well. As a result of these activities it is clear that Spain is a core area for the Company. A major position has been acquired in the oil-prone Sedano Basin. These licences have become all the more attractive as our technical staff examine the deeper prospects in the basin which have in addition to oil potential a very large potential for gas sourced from the local coal measures which outcrop and were mined to the northwest. Early in 2002 we assumed the management control of our key South of England licences and have now increased our interest in them from 20% to 40%. In 2002 we acquired an additional 15% interest from Black Rock Plc by an inexpensive farm-in, bringing our interest up to 35% in each of PEDL 098, 099 and 113. In early 2003 we acquired from Italmin Petroli S.r.l. a further 5% in the same three licences simultaneous with surrender of our 10% interest in the Fiume Arrone licence. Following detailed technical work our team has upgraded its evaluation of Sandhills-1 to a substantial logged oil discovery independently evaluated at 9.8 million barrels of "probable" oil reserves using a 20% estimated recovery factor, 3.9 million barrels net to Northern, increasing to 6.2 million barrels if the "possible" reserves are included. Approaches are in progress to gain planning consents to re-drill and test Sandhills later this year. This one project is capable of transforming the perceived value of your company. The detailed petrophysical work has given rise to the identification of a number of other targets for new licence applications which must remain undisclosed for commercial reasons. During 2002 we announced that we had entered into arbitration proceedings under English Law with a Lukoil subsidiary, Open Joint Stock Company Arkhangelskgeoldobytcha ("AGD") and with the seat of arbitration subsequently transferred to London. On February 14th 2003 we submitted our full case for damages and awaited responses. Replies have been received from the lawyers acting for AGD. Despite requests AGD has repeatedly failed to respond directly to Northern's reasonable attempts to resolve issues through commercial discussions, thereby saving legal costs. We have found their stance to be obstructive. It has been reported to us that the Tedin field produced approximately 1.25 million barrels during 2002 and we continue to regard ourselves as to be entitled under contract to a 10.34% share of the net profits from the sale of that oil. Having taken advice on financial reporting standards, all the investment costs associated with the Russian venture have now been provided for, save for a nominal one pound. I wish to emphasise that this in no way reflects the potential value of the investment. Whilst we do not expect the unsatisfactory standards of behaviour we have encountered to change to those expected from a Western partner, we will continue to attempt to realise the proper value through the arbitration proceedings. Progress in Italy has been made with the award of two licences. One is the highly productive Po Valley region and the other is offshore, to the south of Sicily. Five further applications are outstanding of which only one is the subject of competition. Italy remains a region of great interest, but for the time being we must accept the slow pace of licensing and concentrate our efforts elsewhere. Inevitably, some of the projects we have undertaken have not worked out for us. I have to report, sadly Peru was one of these where deal terms deteriorated at the last moment. I take it as one of your Company's many strengths that we maintain tough deal criteria and are prepared to walk away when our standards cannot be met. As a result of our efforts last year, particularly by our technical team, we are now in a position to pursue our Spanish and South of England projects in the coming year. We are well funded. We expect to drill two or three appraisal wells in the Isle of Wight and Spain and begin a programme for the increase of oil production from the Ayoluengo field. I look forward to reporting on the progress of these activities during the coming year. Richard Latham Chairman RESULTS SUMMARY The results for the Group for the year ending 31 December 2002 show a profit of # 0.241 million compared with a loss of #(6.437) million for the year ended 31 December 2001. The major components of this result were the #1.777 million exceptional profit on disposal of the Group's Irish interests, offset by the #0.732 million exceptional provision against the Group's Russian investment and a #0.228 million exceptional provision against the value of the Group's investment in Ramco Energy Plc. The operating loss excluding all exceptional items for the year under review was #0.444 million compared with a restated figure for the prior year of #0.9 million (restated to reflect the previous year's writedown against the Russian investment as an exceptional item). This improvement is in part as a result of increased revenues and reductions in administrative expenses. Actual production net to Northern was 13,950 barrels of oil equivalent, with an average price received for oil during the second half of 2002 of US$28.50 per barrel. However attributable production for the year only totalled 1,610 barrels of oil equivalent, as in order to conform with Financial Reporting Standards 5 and 7, the Group was only able to report revenues from the Ayoluengo field from 12 December 2002. Therefore the net income for the period to 12 December of #43,372 has had to be taken to the balance sheet as an adjustment to the purchase price, as disclosed in note 11. If the purchase had of been treated as completed on 1 July 2002, the following figures in respect of the Ayoluengo field would have been included within the Consolidated Profit & Loss account for the year to 31 December 2002: # Turnover 254,787 Operating costs (186,096) Gross profit 68,691 Taxation (19,662) Actual net profit - Ayoluengo 49,029 Amount taken to balance sheet (43,372) Reported net profit - Ayoluengo 5,657 Management consider that such an adjustment does not reflect the true worth of the assets purchased, and as a consequence the balance sheet shows negative goodwill (note 8), indicating that the Group has acquired assets for less than they are actually worth. TAXATION As there was limited UK cash flow during the year, except for interest on surplus funds, the Group further increased its available UK tax losses. However as a result of profits made on the sale of our Irish interests, and net revenues from Spanish operations, the Group is for the first time liable to pay overseas tax. For more detailed information please refer to note 5 within this announcement. CAPITAL STRUCTURE The capital structure of the Group did not materially change during the year. A limited share placing was carried out in January 2002, and the Group issued shares during the first seven months of the year to fund some acquisitions. RISK ASSESSMENT The Group's oil and gas activities are subject to a range of financial and operational risks, as described below, which can significantly impact its performance. LIQUIDITY AND INTEREST RATE RISKS As with previous years, in the first half of 2002 the overriding financial risk to the Group was that of liquidity. The position was highlighted by the material cash outflows on the Irish activity, but was resolved by the Group's decision to sell those interests to Ramco Energy Plc, for an immediate cash injection of #2 million. The sale was completed on 3rd July. In light of the Group's desire to pursue acquisition opportunities, a decision was taken to ensure that all surplus funds remained liquid. The Group continually reviews whether a potential increase in interest income could be derived from a more aggressive strategy with regard to the investment of surplus liquid funds; however, it is considered that any potential benefit from such a strategy is limited given current interest rate levels, and would be outweighed by the consequential loss of flexibility in terms of use of the surplus funds. With surplus funds and no debt financing for projects, the Group had no external debt during the year. This strategy will be reviewed in the light of project developments and new project opportunities. CURRENCY RISK Due to the limited income and expenses denominated in foreign currencies, it was not considered cost effective to manage transactional currency exposure. In addition, the revenues and costs associated with the Group's first production are predominantly in Euros and are thus naturally hedged. It should be noted that the major capital expenditures in the year were denominated in either sterling or euros. As a result of the Group's significant investment in the Russian project, which is denominated in US dollars, movements in the US dollar/sterling exchange rate can significantly affect the Group's balance sheet. Due to the capital structure of the Group, it is not possible to manage this exposure on an active basis. Exchange differences that arise on consolidation are taken to reserves. FINANCIAL INSTRUMENTS In light of the position as set out above, it was not considered an appropriate policy for the Group to enter into any hedging activities or trade in any financial instruments, such as derivatives. OPERATIONAL RISK Operational risks include equipment failure, well blowouts, pollution, fire and the consequences of bad weather. Where the Group is project operator of a producing field, it takes increased responsibility for ensuring that all relevant legislation is met, and that all partners have appropriate insurance cover in place. The Group's insurance policies contain overall limits and deductibles. J M White Finance Director Consolidated Profit and Loss Account Year ended Year ended Year ended Year ended Year ended Year ended 31 December 31 December 31 December 31 December 31 December 31 December 2002 2002 2002 2001 2001 2001 Notes # # # # # # Acquisitions Continuing Total Continuing Discontinued Total Operations Operations Operations Turnover 3 Group turnover 29,398 - 29,398 - 2,663 2,663 and share of joint venture Less: share of - - - - (2,663) (2,663) joint venture Group turnover 29,398 - 29,398 - - - and share of joint venture Cost of sales Production 16,258 - 16,258 - - - costs Depreciation, 2,023 90,737 92,760 88,301 - 88,301 depletion and amortisation Provision - - - - 5,818 5,818 against loan to joint venture 18,281 90,737 109,018 88,301 5,818 94,119 Gross (79,620) (94,119) profit/(loss) Administrative (396,331) (461,560) expenses Other operating 31,500 - income Provision - (301,037) against debtor Operating loss (444,451) (856,716) Share of - (43,447) operating loss in joint venture Total operating (444,451) (900,163) loss: Group and share of joint venture Profit on 4a) 1,776,741 - disposal of oil and gas assets Provision 4b) (731,820) (5,672,273) against fixed asset investment Profit on - 84,218 liquidation of associated company Loss on 4c) (15,164) - disposal of current asset investment Provision 4c) & (227,940) - against current 10 asset investment Interest 37,845 51,479 receivable Profit/(loss) 395,211 (6,436,739) on ordinary activities 5 (154,461) - before taxation Tax on profit on ordinary activities Profit/(loss) 240,750 (6,436,739) for the year Basic 6 0.15p (5.05)p profit/(loss) per share Diluted 6 0.14p (4.39)p profit/(loss) per share Statement of Total Recognised Gains and Losses Year ended Year ended 31 December 31 December 2002 2001 Notes # # Profit/(loss) for the financial year excluding share of loss in joint 240,750 (6,393,292) venture Share of joint venture's loss for the year - (43,447) Profit for the financial year 240,750 (6,436,739) Exchange differences on retranslation of net assets of subsidiary (27,179) 76,832 undertakings Total recognised gains and losses 213,571 (6,359,907) Consolidated Balance Sheet 2002 2001 Notes # # Fixed assets Intangible assets 7 180,965 1,126,703 Negative goodwill 8 (42,595) - Tangible assets 9 164,562 891 Investments 10 1 759,000 Total fixed assets 302,933 1,886,594 Current assets Debtors 392,728 182,944 Investments 772,060 - Cash at bank and in hand 1,806,220 32,107 2,971,008 215,051 Creditors: amounts falling due within one year 396,085 211,245 Net current assets 2,574,923 3,806 Creditors: amounts falling due after more than one year 38,130 - Provisions for liabilities and charges 76,260 - Total assets less liabilities 2,763,466 1,890,400 Capital and reserves Called up share capital 6,035,889 5,813,039 Share premium account 5,297,560 4,860,915 Profit and loss account (8,569,983) (8,783,554) Shareholders' funds 2,763,466 1,890,400 Shareholders' funds attributable to - equity shares (1,670,714) (2,543,780) - non-equity shares 4,434,180 4,434,180 2,763,466 1,890,400 The accounts were approved by the Board of directors on 14 May 2003 and were signed on its behalf by: R H R Latham D R Musgrove Consolidated Statement of Cash Flows Year ended Year ended 31 December 31 December 2002 2001 Notes # # Net cash outflow from operating activities 11a) (637,849) (282,019) Returns on investments and servicing of financing Interest received 37,845 51,479 Capital expenditure and financial investments 11b) (148,603) (936,937) Acquisitions and disposals 11c) 1,999,850 - Cash outflow before financing 1,251,243 (1,167,477) Financing Issue of ordinary shares for cash (net of commissions) 11e) 522,870 10,000 Increase/(decrease) in cash in the year 1,774,113 (1,157,477) Reconciliation of net cash flow to movement in net funds 11f) Increase/(decrease) in cash in the year 1,774,113 (1,157,477) Net funds 1 January 32,107 1,189,584 Net funds 31 December 1,806,220 32,107 Notes to the Accounts 1. BASIS OF PREPARATION The financial information presented in this announcement does not constitute statutory accounts within the meaning of s240 of the Companies Act 1985. The information has however been extracted from the Company's statutory accounts for the year ended 31 December 2002 which were approved by the Board on 14 May 2002 and on which the Company's auditors have given an unqualified opinion. 2. ACCOUNTING POLICIES Accounting convention The accounts have been prepared under the historical cost convention and in accordance with applicable UK accounting standards. The financial statements fall within the scope of the Statement of Recommended Practice ("SORP"), "Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities", issued by the Oil Industry Accounting Committee. The financial statements, including disclosures, have been prepared in accordance with the provisions of the SORP currently in effect. In preparing the financial statements for the current year, the group has adopted FRS 19 'Deferred Tax'. The adoption of FRS 19 has resulted in a change in accounting policy for deferred tax. Deferred tax is recognised on a full provision basis, subject to certain exceptions, in accordance with the accounting policy described below. Previously, deferred tax was provided for on a partial provision basis, whereby provision was made on all timing differences to the extent that they were expected to reverse in the future without replacement. This change in accounting policy has not resulted in any revisions to the financial statements in either the current or prior year. Basis of consolidation The consolidated financial statements include the financial statements of the Company and its subsidiaries made up to 31 December 2002. The acquisition method of accounting has been adopted, such that the results of subsidiary undertakings acquired or disposed of in the year are included in the consolidated profit and loss account from the date of acquisition, or up to the date of disposal. On consolidation, assets and liabilities of subsidiary undertakings and representative offices which are denominated in foreign currencies are translated into sterling at the rate ruling at the balance sheet date. Income and cash flow statements are translated at average rates of exchange prevailing during the year. Exchange differences resulting from the translation at closing rates of net investments in subsidiary undertakings and of foreign currency representative offices, together with differences between earnings for the year translated at average and closing rates, are dealt with in reserves. The Company has taken advantage of Section 230 of the Companies Act 1985 in not presenting its own profit and loss account. The Group's exploration, development and production activities are generally conducted jointly with other companies. Since these arrangements do not constitute entities in their own right, the financial statements reflect the relevant proportion of costs, revenues, assets and liabilities applicable to the Group's interests. Entities in which the Group holds an interest on a long term basis and which are jointly controlled by the Group and one or more other venturers under a contractual arrangement are treated as joint ventures. In the Group accounts, joint ventures are accounted for using the gross equity method. Russian business environment The Group's Russian operations are currently subject to the unique economic, political and social risks inherent in doing business in the Russian Federation. These include matters arising out of the policies of the Russian government, economic conditions, imposition of or changes to taxes or other similar changes by regulatory bodies, foreign exchange controls and uncertainty over contract rights and enforceability. Turnover Turnover is recognised on an entitlement basis and represents the sales value, net of value added and similar taxes, of the Group's share of oil and gas revenue in the year. Income charged, net of value added and similar taxes, to other companies by the Group in respect of fees for acting as operator of both production and pre-production activities is disclosed within other operating income. Depreciation The cost of fixed assets is written off by equal annual instalments over their expected useful lives, as follows: Computer and office equipment - four years Fixtures and fittings - four years The carrying values of tangible fixed assets are reviewed for impairment if events or changes in circumstances indicate the carrying value may not be recoverable. Oil and gas projects Production assets Depreciation, depletion and amortisation Amortisation of expenditure held in each tangible cost pool is provided using the unit of production method based on entitlement to proved and probable reserves of oil and gas and estimated future development expenditure to be incurred to access these reserves. Changes in reserves are accounted for prospectively. Decommissioning costs Provision for decommissioning is recognised in full at the commencement of oil and gas production, or when the assets are first acquired, if later. The amount recognised is the present value of the estimated future expenditure. A corresponding tangible fixed asset is also created at an amount equal to the provision. This is subsequently amortised as part of the capital costs of the production facilities. Any change in the present value of the estimated expenditure is reflected as an adjustment to the fixed asset. Non-production assets The Group has adopted the full cost accounting policy for expenditure on oil and gas projects. As a result, all costs are accumulated in cost pools and are then written off to the extent that they are not supported by underlying oil and gas reserves, unless the expenditure relates to an area where it is too early to make such a decision. Expenditure in the latter category has been included on the balance sheet under intangible assets. Stocks Stocks comprise of oil and gas in tanks and parts and supplies, all of which are stated at the lower of cost and net realisable value. Foreign currencies Transactions in foreign currencies are translated into sterling or, in the case of Group companies with functional currencies other than sterling, at the rate of exchange ruling at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are retranslated at the rate of exchange ruling at the balance sheet date. All differences are taken to profit and loss account. Deferred taxation Deferred tax is recognised in respect of all timing differences that have originated but not reversed at the balance sheet date where transactions or events have occurred at that date that will result in an obligation to pay more, or a right to pay less or to receive more, tax, with the following exceptions: * provision is made for tax on gains arising from the revaluation (and similar fair value adjustments) of fixed assets, and gains on disposal of fixed assets that have been rolled over into replacement assets, only to the extent that, at the balance sheet date, there is a binding agreement to dispose of the assets concerned. However, no provision is made where, on the basis of all available evidence at the balance sheet date, it is more likely than not that the taxable gain will be rolled over into replacement assets and charged to tax only where the replacement assets are sold; * provision is made for deferred tax that would arise on remittance of the retained earnings of overseas subsidiaries, associates and joint ventures only to the extent that, at the balance sheet date, dividends have been accrued as receivable; * deferred tax assets are recognised only to the extent that the directors consider that it is more likely than not that there will be suitable taxable profits from which the future reversal of the underlying timing differences can be deducted. Deferred tax is measured on an undiscounted basis at the tax rates that are expected to apply in the periods in which timing differences reverse, based on tax rates and laws enacted or substantively enacted at the balance sheet date. Cash and liquid resources Cash, for the purposes of the cash flow statement, comprises cash in hand and deposits repayable on demand. Liquid resources comprise funds held in term deposit accounts. 3. SEGMENTAL INFORMATION All turnover in 2002 relates to income from the group's oil and gas assets, and is analysed as follows: Year ended Year ended 31 December 31 December 2002 2001 # # Spain (from 12 December 2002) 29,398 - The profit/(loss) before interest for the year is analysed by geographical area as follows: Year ended Year ended 31 December 31 December 2002 2001 # # United Kingdom & Ireland 1,550,936 (50,348) Spain (2,121) - Rest of Europe (815,906) (6,012,093) Common costs (375,543) (425,777) Profit/(loss) before interest 357,366 (6,488,218) Net interest 37,845 51,479 Tax on profit on ordinary activities (154,461) - Profit/(loss) for the year 240,750 (6,436,739) Miscellaneous common costs have not been apportioned to geographical areas. The loss before interest for the year for the United Kingdom & Ireland and Rest of Europe corresponds to the categories analysed in the 2001 accounts as follows: Year ended 31 December 2001 # United Kingdom (84,571) Ireland (6,548) Share of operating loss in joint venture (43,447) Profit on liquidation of associated company 84,218 United Kingdom & Ireland (50,348) Russia (6,002,545) Italy (9,548) Rest of Europe (6,012,093) The net operating assets/(liabilities) are analysed by geographical area as follows: Year ended Year ended 31 December 31 December 2002 2001 # # Operating assets: United Kingdom & Ireland (32,258) 996,436 Spain 149,127 34,208 Rest of Europe 3,160 827,649 South America 16,707 - 136,736 1,858,293 Non-operating assets: Interest bearing loan 48,450 - Current asset investment 772,060 - Cash 1,806,220 32,107 2,626,730 32,107 2,763,466 1,890,400 4. EXCEPTIONAL ITEMS a) Sale of business Year ended Year ended 31 December 31 December 2002 2001 # # Proceeds from sale of subsidiary 3,000,000 - Satisfied by: Shares in unlisted investment 1,000,000 - Cash 2,000,000 - 3,000,000 - Net assets disposed of: Intangible assets 1,223,109 - Cash 150 - 1,223,259 - Profit on sale of subsidiary 1,776,741 - The business sold during the year contributed #(3,215) to the group's operating loss for the year. b) Provision against fixed asset investment Year ended Year ended 31 December 31 December 2002 2001 # # Charge for the year (731,820) (5,672,273) For a full explanation of this provision please refer to note 10. c) Loss and provision against current asset investments Year ended Year ended 31 December 31 December 2002 2001 # # Loss on disposal of current asset investment (15,164) - Provision against current asset investment (227,940) - 5. TAX ON PROFIT ON ORDINARY ACTIVITIES a) Analysis of tax charge Year ended Year ended 31 December 31 December 2002 2001 # # Current tax: Overseas tax on profit on disposal of oil and gas assets 155,000 - Overseas tax (539) - Total current tax (note 7b) 154,461 - b) Factors affecting tax charge The tax charge is lower than the standard rate of corporation tax in the UK (30%). The difference is explained below: Year ended Year ended 31 December 31 December 2002 2001 # # Group profit/(loss) on ordinary activities before tax 395,211 (6,436,739) Tax on group profit on ordinary activities before tax @ 30% 118,563 (1,931,022) Effects of: Gains not taxable in the UK (530,022) - Current tax losses not utilised 410,823 1,931,022 Overseas tax on profit on disposal of oil and gas assets 155,000 - Overseas tax 97 - Current tax charge for period 154,461 - c) Factors that may affect future tax charges The Group and Company have tax losses arising in the UK of approximately #2.70m (2001 - #2.15m) and #2.47m (2001 - #2.0m) that are available indefinitely for offset against future taxable profits of those companies in which the losses arose. Deferred tax assets have not been recognised in respect of these losses as they may not be used to offset taxable profits elsewhere in the Group, and they have arisen in subsidiaries that may be loss making for some time. The approximate value of the unrecognised tax assets for the Group and Company are #0.81m (2001 - #0.66m) and #0.74m (2001 - #0.62m) respectively. No deferred tax is recognised on the unremitted earnings of overseas subsidiaries and joint ventures. As the earnings are continually reinvested by the Group, no tax is expected to be payable on them in the foreseeable future. 6. PROFIT PER SHARE The basic and diluted profit per share is calculated by reference to the profit for the year of #240,750 (2001: loss of #6,436,739) and the weighted average number of ordinary shares in issue during the year of 157,522,599 (2001: 127,371,748). 7. INTANGIBLE ASSETS Intangible assets represent the cost of investment in oil and gas projects where it is too early to make a decision regarding the existence or otherwise of commercial reserves. United Kingdom & Ireland # Rest of South America Spain Europe # Total # # # Group Cost: At 1 January 2002 1,102,599 34,208 207,950 - 1,344,757 Additions 291,256 39,123 21,022 16,707 368,108 Disposals (1,223,109) - - - (1,223,109) At 31 December 2002 170,746 73,331 228,972 16,707 489,756 Amortisation: At 1 January 2002 78,753 - 139,301 - 218,054 Charge for the year 10,986 13,238 66,513 - 90,737 89,739 13,238 205,814 - 308,791 Net book value: At 31 December 2002 81,007 60,093 23,158 16,707 180,965 At 31 December 2001 1,023,846 34,208 68,649 - 1,126,703 On 4 July 2002, the group disposed of its fully owned subsidiary, Northern Exploration Limited, which held licence interests in respect of the Seven Heads and Galley Head fields. Full details of this disposal are disclosed within note 4a). 8. NEGATIVE GOODWILL Negative goodwill has arisen because the fair value of oil and gas assets purchased as detailed in Note 9 is greater than the consideration paid. # Group Cost: At 1 January 2002 - Additions (43,372) At 31 December 2002 (43,372) Amortisation: At 1 January 2002 - Credit for the year 777 777 Net book value: At 31 December 2002 (42,595) At 31 December 2001 - In accordance with accounting standards, the company has the opportunity to reassess the fair value of assets acquired in its financial statements for the year ended 31 December 2003. 9. TANGIBLE ASSETS Oil and Gas Computer Fixtures Assets (Spain) equipment and fittings Total # # # # Group Cost: At 1 January 2002 - 8,473 213 8,686 Acquisition of oil and gas interests 123,339 - - 123,339 Net cash received (43,372) - - (43,372) 79,967 - - 79,967 Additions - 11,004 - 11,004 Decommissioning provision 76,260 - - 76,260 At 31 December 2002 156,227 19,477 213 175,917 Depletion, depreciation and amortisation: At 1 January 2002 - 7,635 160 7,795 Charge for the year 2,800 707 53 3,560 At 31 December 2002 2,800 8,342 213 11,355 Net book value: At 31 December 2002 153,427 11,135 - 164,562 At 31 December 2001 - 838 53 891 The carrying value of oil and gas assets includes the acquisition cost of a 45% interest in the producing Ayoluengo field purchased by the company's wholly owned subsidiary, Northern Petroleum Exploration Limited. This acquisition became unconditional on 12 December 2002. The acquisition was funded entirely in cash. The company has performed an initial fair value review at 31 December 2002, and considers the total value of assets purchased to be equal to the acquisition cost, before the accounting adjustment made in respect of the net income for the period to 12 December which has been treated as an adjustment to the purchase price. 10. INVESTMENTS Group # Cost: At 1 January 2002 6,431,273 Additions - Exchange difference on revaluation (616,801) At 31 December 2002 5,814,472 Provision: At 1 January 2002 5,672,273 Provided during the year 731,820 Exchange difference on revaluation (589,622) At 31 December 2002 5,814,471 Carrying value at 31 December 2002 1 Carrying value at 31 December 2001 759,000 The investment of #1 represents a nominal value only, after write-offs in conformity with the requirements of Financial Reporting Standard (FRS) No. 11, Impairment of Fixed Assets and Goodwill. This investment, which is a 10.34% net profit interest in both the Tedin and Rossikhin oil fields results from payments made under the terms of a financing agreement between Northern Petroleum Limited ("NPL") and Arkhangelskgeologiya ("AG") dated 25th August 1995 and subsequently assigned to Arkhangelsgeoldbuycha ("AGD"). Under the agreement funds were invested in Polar Bear JSC. The investment is carried on the basis of direct cost, plus the cost of acquisition of NPL, a wholly owned subsidiary of the Company, and the cost of rights held by Chinevale Limited, also a wholly owned subsidiary of the Company, less amounts subsequently provided for. No further investment has been made since balance sheet date. The Company had previously been advised that development operations had been carried out on the Tedin field. Such operations were carried out without reference or financial recourse or other to NPL. In view of the lack of communication from AGD, the company served a notice of arbitration upon AGD (as permitted by the financing agreement referred to above) on 14th June 2002, the purpose of which was to uphold NPL's rights earned in terms of the financing agreement. Whilst an arbitration tribunal has been composed, the matter has yet to reach a hearing. The Company has also been advised that Polar Bear JSC no longer exists as a legal entity, although this does not affect NPL's rights as described above. In view of the immaterial carrying value after the write-off, it has been decided to continue to categorise the asset as an investment. 11. NOTES TO THE STATEMENT OF CONSOLIDATED CASH FLOWS (a) Reconciliation of operating loss to net cash outflow from operating activities: Year ended Year ended 31 December 31 December 2002 2001 # # Operating loss (444,451) (856,716) Depreciation, depletion and amortisation 93,537 88,301 Amortisation of negative goodwill (777) - Depreciation - non oil and gas tangible assets 760 813 Decrease/(increase) in operating debtors and prepayments (338,034) 314,177 Increase/(decrease) in operating creditors and accruals 51,116 171,406 (193,398) 273,660 Net cash outflow from operating activities (637,849) (282,019) (b) Capital expenditure and financial investment: Year ended Year ended 31 December 31 December 2002 2001 # # Purchase of tangible fixed assets (90,971) (308) Expenditure on oil and gas assets (307,343) (1,143,939) Less: Expenditure satisfied by the issue of share capital 61,750 207,310 (245,593) (936,629) Purchase of current asset investment (203,125) - Less: Expenditure satisfied by the issue of share capital 203,125 - - - Sale of current asset investment 187,961 - Net cash outflow from capital expenditure and financial investment (148,603) (936,937) (c) Acquisitions and disposals: # Sale of subsidiary undertaking (note (d)) 2,000,000 Net cash transferred with subsidiary undertaking (150) 1,999,850 (d) Sale of business: # Net assets disposed of: Intangible assets 1,223,109 Cash 150 Profit on disposal 1,776,741 3,000,000 Satisfied by: Shares in unlisted investment 1,000,000 Cash 2,000,000 3,000,000 (e) Reconciliation of issue of new ordinary shares with cash received in the year: # Cash received in 2002 in respect of 2001 issue of ordinary shares (including premium upon issue) 128,250 Issue of new ordinary shares (including premium upon issue) 659,495 Less: Share capital issued for acquisition of assets (264,875) Cash received from issue of new ordinary shares 522,870 (f) Analysis of net funds: At At 1 January Cash 31 December 2002 flow 2002 # # # Cash at bank 32,107 1,774,113 1,806,220 12. ANNUAL GENERAL MEETING The annual general meeting of the Company will be held at No.1 Cornhill, London EC3V 3ND on 9 July 2003 at 10.00am. 13. ANNUAL REPORT AND FINANCIAL STATEMENTS Copies of the Annual Report and Financial Statements will be circulated to shareholders shortly and may be obtained after the posting date from the Company Secretary, Northern Petroleum Plc, No.1 Cornhill, London, EC3V 3ND. Full details will also be available on our website, www.northpet.com. This information is provided by RNS The company news service from the London Stock Exchange END FR USSNROSRVAAR
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