Ascent Resources Regulatory News (AST)

Ascent Resources plc / Epic: AST / Index: AIM / Sector: Oil and Gas

2 June 2011

Ascent Resources plc ('Ascent' or 'the Company')

Final Results

Ascent Resources plc, the AIM-traded oil and gas production and exploration company, announces its final results for the year ended 31 December 2010.

Overview

·; Progressed and refined portfolio of low cost, onshore oil and gas assets with near-term upside potential across Europe - Hungary, Slovenia, Switzerland, Italy, and the Netherlands

·; Advanced the Petišovci/Lovászi/Ujfalu tight gas project in Slovenia/Hungary towards production - P50 gas in place estimates of 412 Bcf. (11.7 Bm3; 68.7 MMboe)

·; Confirmed gas in all of the six Middle Miocene Badenian reservoirs and flow tested gas from the Lower Miocene Karpatian reservoir at Petišovci project - potential to increase gas in place estimate by in excess of 100 Bcf, with preliminary results of Pg-11A expected to be released shortly

·; Established active development programme at Frosinone/Strangolagalli project in Italy

·; Sold 90% interest in Hermrigen/Essertines/Linden project in Switzerland to eCORP Europe International Ltd. for €8 million cash - retained various back-in options on specific potentially successful discoveries

·; Strengthened balance sheet post year end with a £17 million placing to institutional investors at 5 pence per share

·; Continued production at 48.8% held Penészlek project in Hungary, currently generating gross gas sales of approximately €300,000 per month

·; Made changes on a corporate level including appointment of new Nominated Adviser and Broker and strengthened Board

CHAIRMAN'S STATEMENT

I am pleased to report that 2010 was a year of solid progress for Ascent both operationally and in terms of positioning the Company for steady near- and long-term growth in shareholder value.

Our strategy remains to combine lower risk field redevelopment projects in areas with existing infrastructure with selected higher risk exploration projects all designed to provide a balanced risk/reward profile with good potential upside. To this end, we have a diversified portfolio of principally onshore, hydrocarbon exploration, redevelopment and appraisal interests across five European countries: Hungary, Slovenia, Switzerland, Italy, and the Netherlands. We are initiating relatively simple development models to advance these projects, utilising the latest technology and working with local organisations in each jurisdiction to increase efficiency. As a result of the work undertaken during 2010 and 2011, we anticipate ramping up production towards the end of 2011 and beyond.

Our primary near-term objective is to advance the Petišovci/Lovászi/Ujfalu tight gas project in Slovenia/Hungary. We now hold a 75% interest in the Petišovci asset, having acquired a further 48.75% from EnQuest PLC post year end in return for a 22.5% equity stake in Ascent and a nil cost option of 150,903,958 additional shares, and a 50% interest in the Lovászi and Ujfalu assets. During the year we had independently verified P50 gas in place estimates for the entire project of 412 Bcf. (11.7 Bm3; 68.7 MMboe) and for that reason we consider it relatively low-risk. The challenge for us in 2011 is not so much finding the gas, which we know is there, but how to unlock this gas in a commercial manner given it is largely a tight gas asset.

Phase 1 of the project's development programme included the drilling of Pg-11 well in December 2010 to define the main project parameters. On completion of drilling in February 2011, we were able to confirm gas in all of the six Middle Miocene Badenian reservoirs as well as, most excitingly and unexpectedly, the Lower Miocene Karpatian reservoir, which we hope will increase the gas in place estimate by in excess of 100 Bcf.. The data collected, in conjunction with the full 3-D seismic which we acquired during the year across the whole project area, has led us to believe that we can extract the gas using modern drilling techniques, either by drilling horizontally or by fraccing. In order to determine the right method to use, Phase 2 of the programme is currently underway with a deeper horizontal sidetrack to enable us to fully delineate the Lower Miocene Karpatian reservoir and depending on these results we may follow this up with a sidetrack well in the Middle Miocene. Subsequently, in the late summer of 2011, we plan to drill another well, Pg-10. Following this, if successful, it is hoped that production can commence before the end of the year. To achieve this target, a simple pipeline connection and a carbon dioxide ('CO2') reduction plant is required to connect any producing wells in the project to the national pipeline network.

Going forward, our development plan envisages 10-15 more wells being drilled over a three- to four-year period. It is estimated that if production from the wells is in line with current projections, that net operating cash flow from the first well brought on stream during 2011 could be €3 million in 2011 rising to €10 million in 2012 and €24 million for the period 2013-2015, based on €7 Mscf. gas pricing. The project's net CapEx however is not inconsiderable requiring in excess of €150m to develop the entire field.

We are also focussed on two other core projects: Hermrigen/Essertines/Linden in Switzerland and Frosinone/Strangolagalli in Italy. The Swiss project is another known oil and gas discovery, which was unexploited due to the low price of gas in 1982 and lack of pipeline infrastructure at that time. We consider that this is also a low risk project as Ascent sold its 90% interest to eCORP European International Ltd ('eCORP') in April 2010 for €8 million, whilst retaining a 45% back-in right on any success for three conventional appraisal prospects and a 22.5% back-in right for a further three secondary conventional prospects for apportioned cost. eCORP anticipates drilling the Hermrigen well early in the summer of 2011 once the permit is received.

Finally, the Frosinone/Strangolagalli oil exploration and redevelopment project in Italy has also been making headway. New seismic was shot last year in the Strangolagalli Concession and this year a latest generation satellite reconnaissance survey was commissioned, enabling us to plan a new three-well drilling programme for 2011/2012. Further seismic has been commissioned at the Frosinone Exploration Licence to identify drilling locations. We are currently exploring our options in terms of financing an exploration programme but as all the drilling would be targeting reservoirs about 1,000 metres deep, costs should be relatively low, yet the upside could be significant for a Company of our size.

Also on the theme of finance, production continues at our 48.8% held Penészlek project in Hungary, where we are currently generating gross gas sales of approximately €300,000 per month. The strong European gas market conditions have been working in our favour; with over 50% of European gas imported and forecast to rise to circa 75% in line with the declining North Sea production, we anticipate these favourable pricing conditions to continue. Production at Penészlek is expected to continue for about another 12 months with another sidetrack well, PEN-105, targeted for the summer of 2011 prior to the field being fully depleted.

The self-financing Penészlek project is useful as it provides the Company with cashflow for overheads, however post the year end in March 2011, it was necessary to raise additional funds by way of a placing in order to progress our core Petišovci/Lovászi/Ujfalu project. We were therefore very pleased to raise £17 million, before expenses, primarily with high quality institutional investors. This has provided the capital to significantly advance our Petišovci/Lovászi/Ujfalu project and we believe that if successful the money could be enough to get us to production/cash flow generation before the year end.

On a corporate level, we have made a number of changes. In September 2010 we appointed finnCap Ltd as the Company's Nominated Adviser and Broker to strengthen our profile within the fund and wealth management arena. Earlier in the same month we also made changes to our Board with the appointment of Dr. Cameron Davies as a Non-executive Director. Cameron is an international energy sector specialist and the former Chief Executive of Alkane Energy plc. He has an excellent track record of exploration success and growing profits in a quoted energy company. He brings with him the technical skills and broad network of international energy industry contacts which will be invaluable in progressing Ascent's extensive portfolio of European oil and gas development and exploration assets.

At the same time, both Legal Director Malcolm Groom and Non-executive Director Jonathan Legg, who had been with the Company since 2005, stepped down from the Board to focus on other commitments. At the end of 2010, Simon Cunningham, our Finance Director, also stepped down from the Board to re-locate to Australia. I would like to take this opportunity to thank them all for their work during their long association with Ascent.

Simon was replaced by Scott Richardson Brown as Executive Finance Director, who had been appointed in November 2010 as a Non-executive Director. Scott is a qualified Chartered Accountant and subsequent to his experience as an auditor, he spent over 10 years working with AIM, FTSE 250 and FTSE 100 companies, both in a corporate finance advisory role and, recently, as Corporate Finance and Investor Relations Director of CSR plc.

Additionally, post the year end, as part of the agreement with EnQuest PLC, Graham Cooper was nominated to join our Board as a Non-executive Director in February 2011. Graham brings with him a wealth of experience which will be very valuable to the Company. EnQuest will also provide technical support to Ascent for the Petišovci Project, as well as for the evaluation of future European business development opportunities.

With a strong team in place as well as a solid investor base, a healthy balance sheet and an exciting portfolio of diversified assets, the outlook for 2011 and beyond is highly encouraging. Having proved up our core portfolio we are now focussed on extracting value from it and in line with this, aggressive work programmes are underway. The Petišovci/Lovászi/Ujfalu tight gas project is particularly promising, which in tandem with our other projects, will, I am confident, create real and lasting value for our shareholders.

John Kenny

Chairman

2 June 2011

OPERATIONS REVIEW

Ascent Resources plc is a multi-project oil and gas exploration company, with interests in five European countries: Hungary, Slovenia, Switzerland, Italy and the Netherlands. The Company focuses primarily on low cost, onshore oil and gas assets with high upside potential. Modern exploration and development techniques are utilised to maximise profitability, whilst operating through local entities with local employees provides substantial advantages leading to greater efficiency and know-how.

Ascent's balanced portfolio targets projects which are in areas with a proven hydrocarbon system and largely in areas with existing or nearby infrastructure, either pipelines for gas or refineries for oil. The Company has three core projects and a large portfolio of other assets to be matured for inclusion in the core portfolio after the completion of early stage, geological and geophysical work programmes and by following an asset-management (farm-out/farm-down) strategy.

Core Projects

Petišovci/Lovászi/Ujfalu - Slovenia/Hungary

(Petišovci - 75% interest / Lovászi/Ujfalu - 50% interest)

A phased exploration and development programme at the Petišovci-Lovászi tight gas project, which straddles the Slovenian/Hungarian border, commenced during 2009 with the acquisition of 3-D seismic. The conclusion of Phase 1 in the coming months, will provide the project with two fully evaluated modern wells, from which the overall redevelopment of the Petišovci Globocki reservoir can be planned, and a third state-of-the-art well in the Hungarian part of the project area.

The first well is the 3,050m Pg-11 well, the drilling and evaluation of which was completed post year end in February 2011. This was the first well to be drilled in 22 years on the project area, which has an independent P50 estimate of gas-in-place estimate of 412 Bcf. (11.7 Bm3; 68.7 MMboe).

The primary objectives of the Pg-11 appraisal well were satisfied with gas confirmed by logs in all of the six Middle Miocene Badenian reservoirs. In addition, and unexpectedly, gas and condensate were sampled from the Lower Miocene Karpatian reservoir, which it is hoped will contribute to an increase in the gas-in-place estimates. Gas also flowed for the first time from the shallowest 'A' sands. These results substantially de-risk the project and underpin its commercial potential.

In April 2011 we commenced phase two of the Pg-11 well by drilling the sidetrack Pg-11A. The purpose was to fully delineate the Karpatian reservoir, which was unexpectedly encountered whilst drilling Pg-11, and to log and test part of the well to gather more data to determine any exploitation strategy.

Whilst Pg-11 was drilled in the eastern part of the field, the second appraisal well, Pg-10, is planned for the western part of the field and the drilling location is under construction so that the rig can move there immediately from the Pg-11 location.

It is intended to complete both of these wells so that production can commence later in 2011. As CO2 is present, a CO2 scrubber might be necessary so that the gas can be sold in to the Geoplin national pipeline network that has a maximum CO2 concentration limit of 1.5%

Phase 2 of the project will commence in 2012 after the data from Phase 1 is fully integrated into the geological model and the redevelopment of the field has been fully planned. At the present time, we think between 10 and 15 wells will be required to develop the reserves in the Slovenian half of the project.

Outside of the Petišovci field but within the project area a number of exploration targets are present and plans for these wells are also being considered for the 2012 drilling campaign. Additional wells, depending on the outcome of the Ujfalu III exploration and appraisal well will also be considered in the Hungarian half of the project area.

Hermrigen/Essertines/Linden - Switzerland

(45% back-in right on any success for three conventional appraisal prospects and a 22% back-in right for a further three conventional secondary prospects for apportioned cost of drilling)

In April 2010 Ascent sold its 100% owned Swiss subsidiary, PEOS AG ('PEOS'), to eCORP Europe International Ltd. ('eCORP'), for a cash consideration of €8 million, but retained various back-in options on specific potentially successful discoveries. The projects held within PEOS are estimated by Tracs International to contain gross contingent conventional resources in excess of 600Bcf. of gas.

As part of the Transaction, eCORP has irrevocably committed to drill the Hermrigen-2 appraisal well prior to October 2011, however, as the site construction permit has not yet been issued, the drilling rig contract is not yet in place.

Management estimate gross contingent reserves of potentially 150Bcf. in the Muschelkalk and Bunter layers of the Hermrigen prospect. eCORP will fund the entire cost of the Hermrigen-2 well and, if successful, Ascent has the retrospective right to participate by paying 45% of the conventional well cost to earn a 45% interest in the conventional discovery. Ascent has no rights to any unconventional gas development or gas storage project should it be undertaken by eCorp. Ascent retains the equivalent rights for the appraisal of the Essertines 1 and Linden 1 appraisal wells should eCORP elect to drill these prospects. Should eCorp elect not to drill these wells Ascent retains the option, subject to certain conditions, to fund their development in its own right.

Additionally, Ascent and eCORP have identified a further three prospects in the licence areas held by PEOS. Should eCORP elect to drill these additional prospects, Ascent has the right to 22.5% of any successful conventional discovery by paying 22.5% of the drilling costs post discovery. Again, should eCORP elect not to drill these wells Ascent retains the option, subject to certain conditions, to fund their development in its own right.

Frosinone/Strangolagalli - Italy

(80% interest in Frosinone and 50% interest in Strangolagalli)

At the Frosinone Exploration Licence, two wells, Anagni-1 and Fontana 1, were historically drilled with good oil shows. During the period, a satellite reconnaissance survey was commissioned and the results not only show potential in the existing prospects but have also revealed new targets which are substantially larger. New 2-D seismic is planned for these new prospects and acquisition is scheduled for Q3 2011.

Work has been ongoing at the Strangolagalli Concession. Seismic has been acquired over the Ripi oilfield, a proven oil producing area, and permitting is on-going for four redevelopment wells based on this new seismic data. Subject to permitting and financing, a suitable rig is available to drill two wells in later in 2011.

Other Projects

Penészlek project -Eastern Hungary

(48.8% interest)

Production commenced at the Penészlek project from the PEN-105 well in March 2010 and later from the PEN-101 well in May 2010. Both wells are still producing over 1.5 MMscfd of gas, currently generating gross revenue of approximately €300,000 per month. A fully automated production facility is being used, located close to PEN-101, to keep overheads low and profitability high. Production is anticipated to continue for approximately 12 months with PEN-105 sidetrack targeted this summer as one segment of the field becomes fully depleted.

The long-standing PEN-9 project in the northern part of the newly issued Mining Plot (Production Concession) is still under consideration. PEN-9 tested gas when it was originally drilled in 1985 but certain restrictions have so far prevented re-entry and testing of this well; hopefully these restrictions will be surpassed in the near future.

Cento-Bastiglia - Po Valley, Italy

(100% interest)

The same satellite reconnaissance as used for Frosinone was commissioned over this area and over the Fiume Arrone project (Ascent 70%). In Cento-Bastiglia, a number of leads have been identified and seismic will be required to confirm the depth and prospectivity of these leads.

M10/M11 - the Netherlands

(54% interest)

Ascent continues to strengthen its portfolio of non-core, longer term projects. In July 2010, Ascent, through its subsidiary Ascent Resources (Netherlands) BV ('ARN'), increased its interest in the M10/11 block in the southern North Sea off the Netherlands' coast, to 54%. The M10/11 appraisal project is in the shallow waters off the north coast of the Netherlands. The discovery well, M11-1 was drilled by Nederlandse Aardolie Maatschappij ('NAM') in 1985. The area benefits from good quality 3-D seismic coverage and in addition to the discovery in the Rotligendes sandstones, a number of other prospects and leads have been identified. Ascent and the other project partners are considering the drilling of an appraisal well for the Terschelling Noord discovery which was also drilled by NAM in 1992. This structure lies partly within the M10/11 licence area and partly in the area to the south.

The Ministry of Economic Affairs is considering ARN's request for an extension to the expiration date of these licences.

Acquisitions

In September 2010, Ascent acquired a 60% interest in the 1,990 sq. km. Igal-II exploration permit in Central Hungary through its 60% equity interest in Hungarian company Pelsolaj kft ('Pelsolaj'). The exploration permit, to the south east of Lake Balaton, was acquired from Winstar Resources Limited in exchange for a 4% net profit interest derived from future production from the permit area.

Initial exploration will concentrate on a 300 sq. km. area known for pre-Pannonian sediments, which are highly prospective for oil and where a number of shallow leads, circa 1,000 metres, have already been identified. 40km of new 2-D seismic was acquired in September 2010 and drilling locations are under consideration which will be located between three old wells in which the prospective formations have been shown to be present. Importantly, a number of discoveries in similar geological structures nearby produce good quality oil at rates typically in excess of 100 Bopd per well.

Consolidated Income Statement

for the year ended 31 December 2010

Consolidated Statement of Comprehensive Income

for the year ended 31 December 2010

Consolidated Statement of Changes in Equity

for the year ended 31 December 2010

Company Statement of Changes in Equity

for the year ended 31 December 2010

Consolidated Statement of Financial Position

As at 31 December 2010

Consolidated Statement of Financial Position (continued)

As at 31 December 2010

Company Statement of Financial Position

As at 31 December 2010

Consolidated Cash Flow Statement

for the year ended 31 December 2010

Company Cash Flow Statement

for the year ended 31 December 2010

Notes to the Financial Statements

1 Accounting policies

Reporting entity

Ascent Resources plc ('the Company') is a company domiciled and incorporated in England. The address of the Company's registered office is One America Square, Crosswall, London, EC3N 2SG. The consolidated financial statements of the Company for the year ended 31 December 2010 comprises the Company and its subsidiaries (together referred to as the 'Group') and the Group's interest in associates and joint ventures. The parent company financial statements present information about the Company as a separate entity and not about its Group.

The Company is admitted to AIM, a market of the London Stock Exchange.

The consolidated financial statements of the Group for the year ended 31 December 2010 are available from the Company's website at www.ascentresources.co.uk.

Statement of compliance

The Group's and Company's financial statements for the year ended 31 December 2010 were approved and authorised for issue by the Board of Directors on 2 June 2011 and the Statements of Financial Position were signed on behalf of the Board by Jeremy Eng.

Both the Parent Company financial statements and the Group financial statements give a true and fair view and have been prepared and approved by the Directors in accordance with International Financial Reporting Standards as adopted by the EU ('Adopted IFRSs').

Basis of preparation

In publishing the Parent Company financial statements here together with the Group financial statements, the Company is taking advantage of the exemption in s408 of the Companies Act 2006 not to present its individual income statement and related notes that form a part of these approved financial statements.

Measurement Convention

The financial information has been prepared under the historical cost convention except for available-for-sale financial assets and financial instruments which are measured at fair value through profit and loss. The financial statements are presented in sterling and have been rounded to the nearest thousand (£'000s) except where otherwise indicated.

The principal accounting policies set out below have been consistently applied to all periods presented.

Going Concern

The financial statements of the Group are prepared on a going concern basis.

In common with many similar companies, the Group raises finance for its exploration and appraisal activities in discrete tranches. Ultimately, the Group must either raise additional tranches of funding and/or generate sufficient net cash flows from operations.

The Directors are of the opinion that the Group will have sufficient cash to fund its activities based on forecast cash flow information for a period in excess of twelve months from the date of approval of these financial statements. Management continues to monitor all working capital commitments and balances on a weekly basis and believe that they have secured appropriate levels of financing for the Group to continue to meet their liabilities and commitments as they fall due for at least the next twelve months.

In preparing base and sensitised cash flow forecasts the Directors have identified a number of cash receipts and cash payments where they have had to use their best judgement to make certain estimates.

The base case forecasts are prepared using estimates of planned production from producing fields, future gas prices and estimates of costs for planned exploration activities. On a number of projects certain assumptions have also been made with regard to working capital management and matching cash inflows from cash calls to cash outflows.

Accordingly, the Directors have also prepared sensitised forecasts to reflect the risk that production volumes and gas prices may be lower than estimated and exploration costs may be higher. These forecasts indicate that the Group can continue to operate within existing facilities for the foreseeable future. If the amount or timing of forecast inflows and outflows were to change adversely the Group may be required to reconsider discretionary exploration activity and/or seek additional bridging finance to meet any shortfall.

New and amended Standards effective for 31 December 2010 year-end adopted by the Group:

i) The following new standards and amendments to standards are mandatory for the first time for the Group for financial year beginning 1 January 2010. Except as noted, the implementation of these standards is not expected to have a material effect on the Group. 

No other IFRS issued and adopted but not yet effective are expected to have an impact on the Group's financial statements.

(ii) Standards, amendments and interpretations, which are effective for reporting periods beginning after the date of these financial statements which have not been adopted early:

The Group has not yet assessed the impact of IFRS 9. Except for the amended disclosure requirements of IAS 24 (the above revised standards), amendments and interpretations are not expected to materially affect the Group's reporting or reported numbers.

* Not yet endorsed by European Union.

Except for the adoption of IFRS 3 Revised, which would materially affect the presentation and financial impact of a business combination, the above standards, interpretations and amendments will not significantly affect the Group's results or financial position. The adoption of IFRS 9 will eventually replace IAS 39 in its entirety and consequently may have a material affect the presentation, classification, measurement and disclosures of the Group's financial instruments.

Items marked * had not yet been endorsed by the European Union at the date that these financial statements were approved and authorised for issue by the Board.

.

Critical accounting estimates and assumptions

The preparation of the consolidated financial statements in conformity with IFRSs requires management to make estimates and assumptions that affect the application of policies and reported amounts of assets, liabilities, income, expenses and related disclosures. The estimates and underlying assumptions are based on practical experience and various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making the judgments about carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates.

The estimates and underlying assumptions are reviewed on an ongoing basis. Changes in accounting estimates may be necessary, if there are changes in the circumstances on which the estimate was based or as a result of new information. Such changes are recorded in the period in which the estimate is revised.

Critical judgements in applying the Group's accounting policies

The application of the Group's accounting policies may require management to make judgements, apart from those involving estimates, which can have a significant effect on the amounts amortised in the financial statements. Management judgement is particularly required when assessing the substance of transactions that have a complicated structure or legal form.

The key area where management judgement will need to be applied will be in the areas of:

(a) Oil and gas assets - exploration and evaluation costs are initially classified and held as intangible fixed assets rather than being expensed. The carrying value of intangible exploration and evaluation assets are then determined. Management considers these assets for impairment at least annually based on an estimation of the recoverability of the cost pool from future revenues of the related oil and gas reserves (see Note 13);

(b) Decommissioning provision - the cost of decommissioning is estimated by reference to operators and internal specialist staff (see Note 24);

(c) Convertible loan notes - management assessed the fair value of the liability component at issue and continue to review the appropriateness of the amortisation period annually (see Note 23);

(d) Basis of consolidation - management consider the Company's ability to exert financial and operational control, as well as the level of voting rights and representation on the Board as a basis of consolidation;

(e) Business combinations - management assess the fair value of the assets and liabilities acquired based on the assessment of operations and internal specialist staff.);

(f) Share-based payments - management assesses the fair value of each option using an appropriate pricing model based on option and share prices, volatility and the life of the option (see Note 34).

(g) Commercial reserves - Commercial reserves are proven and probable oil and gas reserves, calculated on an entitlement basis. Estimates of commercial reserves underpin the calculation of depletion and amortisation on a unit of e basis. Estimates of commercial reserves include estimates of the amount of oil and gas in place, assumptions about reservoir performance over the life of the field and assumptions about commercial factors which, in turn, will be affected by the future oil and gas price.

Basis of consolidation

The financial statements comprise the consolidation of the accounts of the Company and its subsidiary undertakings and incorporate the results of its share of jointly controlled entities using the proportional consolidation method of accounting. Consistent accounting policies have been used to prepare the consolidated financial statements.

Control is achieved where the Group has the power to govern the financial and operating policies of an investee entity so as to obtain benefits from its activities. The results of undertakings acquired or disposed of are consolidated from or to the date when control passes to or from the Group. For the Company's financial statements only, investments in subsidiary undertakings are stated at cost less provision for impairment.

The results of subsidiaries acquired or disposed of during the period are included in the consolidated income statement from date that control commences until the date that control ceases.

Where necessary, adjustments are made to the results of subsidiaries to bring their accounting policies used into line with those used by the Group.

All intra-Group transactions, balances, income and expenses are eliminated on consolidation.

The total comprehensive income of non-wholly owned subsidiaries is attributed to owners of the parent and to the non-controlling interests in proportion to their relative ownership interests. Before this date, unfunded losses in such subsidiaries were attributed entirely to the Group. In accordance with the transitional requirements of IAS 27 (2008), the carrying value of non-controlling interests at the effective date of the amendment has not been restated.

Where the Group acquires an equity interest from non-controlling parties, the excess/(shortfall) between the consideration paid and the element of the reserve for non-controlling interest that has been acquired is taken directly to retained earnings. No gain or loss is recognised through profit or loss.

 Business combinations

On acquisition, the assets, liabilities and contingent liabilities of subsidiaries are measured at their fair values at the date of acquisition. Any excess of cost of acquisition over net fair values of the identifiable assets, liabilities and contingent liabilities acquired is recognised as goodwill. Any deficiency of the cost of acquisition below the net fair values of the identifiable assets, liabilities and contingent liabilities acquired (i.e. discount on acquisition) is credited to profit and loss in the period of acquisition.

Non-current assets held for sale and disposal groups

Non-current assets are classified as held for sale when:

• they are available for immediate sale;

• management is committed to a plan to sell;

• it is unlikely that significant changes to the plan will be made or that the plan will be withdrawn;

• an active programme to locate a buyer has been initiated;

• the asset is being marketed at a reasonable price in relation to its fair value; and

• a sale is expected to complete within 12 months from date of classification.

Non-current assets are held for sale are measured at the lower of:

• their carrying amount immediately prior to being classified as held for sale in accordance with the Group's accounting policy; and

• fair value less costs to sell.

Following their classification as held for sale, non-current assets are not depreciated.

The results of operations during the year are included in the consolidated income statement up to the date of disposal.

A discontinued operation is a component of the Group's business that represents a separate major line of business or geographical area of operations or is a subsidiary acquired exclusively with a view to resale, that has been disposed of, has been abandoned or that meets the criteria to be classified as held for sale.

Discontinued operations are presented in the consolidated income statement (including the comparative period) as a single line which comprises the post tax loss of the discontinued operation. Operations are classified as discontinued when the decision is made to dispose of the operation by the Directors and the operations are actively marketed.

Interest in jointly controlled entities

A joint venture is a contractual arrangement whereby the Group and other parties undertake an economic activity that is subject to joint control.

Where a company undertakes its activities under a joint venture arrangement directly, the Group's share of jointly controlled assets and any liabilities incurred jointly with the other ventures are recognised in the financial statements of the relevant Group Company and classified according to their nature.

Similarly, income from the sale and use of the Group's share of the output of jointly controlled assets and its share of joint venture expenses, are recognised in the financial statements of the relevant Group Company and classified according to their nature.

Interests in Associates

Associates are those entities in which the Group has significant influence, but not control, over the financial and operating policies. Significant influence is presumed to exist when the Group holds between 20% and 50% of the voting power of another entity. Associates are accounted for using the equity method (equity accounted investees) and are initially recognised at cost.

The Group's investment includes goodwill identified on acquisition, net of any accumulated impairment losses. The consolidated financial statements include the Group's share of the income and expenses and other comprehensive income of equity accounted investees, after adjustments to align the accounting policies with those of the Group, from the date that significant influence or joint control commences until the date that significant influence or joint control ceases. When the Group's share of losses exceeds its interest in an equity accounted investee, the carrying amount of that interest (including any long-term investments) is reduced to nil and the recognition of further losses is discontinued except to the extent that the Group has an obligation or has made payments on behalf of the investee.

Increase in interests in jointly controlled entities

When an entity acquires an additional interest in jointly controlled entities the entity's portion of identifiable net assets of the jointly controlled entity acquired is measured at cost at the date of additional investment with any surplus accounted for as goodwill.

Oil and Gas Exploration Assets

The Group follows the 'successful efforts' method of accounting for exploration and evaluation costs. All licence/project acquisitions, exploration and appraisal costs incurred or acquired on the acquisition of a subsidiary, are accumulated in respect of each identifiable project area. These costs, which are classified as intangible fixed assets are only carried forward to the extent that they are expected to be recovered through the successful development of the area or where activities in the area have not yet reached a stage which permits reasonable assessment of the existence of economically recoverable reserves.

Pre-licence/project costs are written off immediately. Other costs are also written off unless commercial reserves have been established or the determination process has not been completed. Thus accumulated cost in relation to an abandoned area are written off in full to the statement of comprehensive income in the year in which the decision to abandon the area is made.

When production commences the accumulated costs for the relevant area of interest are transferred from intangible fixed assets to tangible fixed assets as 'Developed oil and gas assets'.

Impairment of oil and gas exploration assets

Exploration/appraisal assets are reviewed regularly for indicators of impairment following the guidance in IFRS 6 'Exploration for and Evaluation of Mineral Resources' and tested for impairment where such indicators exist. Any impairment arising is recognised in the Income Statement for the year.

Impairment reviews on development/producing assets are carried out on each cash-generating unit identified in accordance with IAS 36 'Impairment of Assets'. Ascent's cash generating units are those assets which generate largely independent cash flows and are normally, but not always, single development areas.

At each reporting date where there are indicators of impairment the net book value of the cash generating unit is compared with the measurable recoverable amount, which is defined as the higher of fair value less costs to sell or value in use. If the net book value is higher, then the difference is written off to the Income Statement as impairment. Forecast production profiles are determined on an asset-by-asset basis using appropriate petroleum engineering techniques.

Where there has been a charge for impairment in an earlier period, that charge will be reversed in a later period where there has been a change in circumstances to the extent that the discounted future net cash flows are higher than the net book value at the time. In reversing impairment losses, the carrying amount of the asset will be increased to the lower of its original carrying value or the carrying value that would have been determined (net of depletion) had no impairment loss been recognised in prior periods. 

Impairment of developed oil and gas assets

When events or changes in circumstances indicate that the carrying amount of expenditure attributable to a successful well may not be recoverable from future net revenues from oil and gas reserves attributable to that well, a comparison between the net book value of the cost attributable to that well and the discounted future cash flows from that well is undertaken. To the extent that the carrying amount exceeds the recoverable amount, the cost attributable to that well is written down to its recoverable amount and charged as an impairment.

Depletion of developed oil and gas assets

Costs carried in each well are depreciated on a unit of production basis using the ratio of oil and gas production in the period to the estimated quantity of commercial proven and probable oil and gas reserves at the end of the period plus production in the period. Costs in the unit of production calculation include the net book value of capitalised costs plus estimated future development costs.

Changes in estimates of commercial proven and probable oil and gas reserves or future development costs are dealt with prospectively.

Decommissioning costs

Where a material liability for the removal of production facilities and site restoration at the end of the field life exists, a provision for decommissioning is recognised. The amount recognised is the net present value of estimated future expenditure determined in accordance with local conditions and requirements. An asset of an amount equivalent to the provision is also added to oil and gas exploration assets and depreciated on a unit of production basis. Changes in estimates are recognised prospectively, with corresponding adjustments to the provision and the associated asset.

Property, plant and equipment assets other than oil and gas assets

Property, plant and equipment other than oil and gas assets are stated at cost, less accumulated depreciation, and any provision for impairment. Depreciation is provided at rates estimated to write off the cost, less estimated residual value of each asset over its expected useful life as follows:

Computer and office equipment - 33% straight line.

Revenue recognition

Oil and gas sales revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for the Group's share of oil and gas supplied in the period.

Inventories

Inventories, including materials, equipment and inventories of gas and oil held for sale in the ordinary course of business, are stated at weighted average historical costs, less provision for deterioration and obsolescence or, if lower, net realisable value.

Foreign currency

The Group's strategy is focused on developing oil and gas projects across Europe funded by shareholder equity and other financial assets which are principally denominated in Sterling. The functional currency of the Company is Sterling.

Transactions in foreign currency are translated to the respective functional currency of the Group entity at the rates of exchange prevailing on the dates of the transactions. At each balance sheet date, monetary assets and liabilities that are denominated in foreign currencies are retranslated to the functional currency at the rates prevailing on the balance sheet date. Exchange gains and losses on short-term foreign currency borrowings and deposits are included with net interest payable.

The assets and liabilities of foreign operations, including fair value adjustments arising on consolidation, are translated to Sterling at foreign exchange rates ruling at the balance sheet date. The revenues and expenses of foreign operations are translated to Sterling at the average rate ruling during the period. Foreign exchange differences arising on retranslation are recognised directly in a separate component of equity. They are released into the income statement upon disposal.

On consolidation, the results of overseas operations are translated into sterling at rates approximating to those ruling when the transactions took place. All assets and liabilities of overseas operations, including goodwill arising on the acquisition of those operations, are translated at the rate ruling at the reporting date. Exchange differences arising on translating the opening net assets at opening rate and the results of overseas operations at actual rate are recognised in other comprehensive income and accumulated in the foreign exchange reserve.

On disposal of a foreign operation, the cumulative exchange differences recognised in the foreign exchange reserve relating to that operation up to the date of disposal are transferred to the consolidated statement of comprehensive income as part of the profit or loss on disposal.

Exchange differences on all other transactions, except relevant foreign currency loans, are taken to operating loss.

Taxation

The tax expense represents the sum of the tax currently payable and any deferred tax.

The tax currently payable is based on the estimated taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group's liability for current tax is calculated using the expected tax rate applicable to annual earnings.

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities for financial reporting purposes and the corresponding tax bases used in the computation of taxable profit. It is accounted for using the balance sheet liability method. Deferred tax liabilities are 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. The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Equity-settled share-based payments

The cost of providing share-based payments to employees is charged to the income statement over the vesting period of the related share options or share allocations. The cost is based on the fair values of the options and shares allocated determined using the Binomial method. The value of the charge is adjusted to reflect expected and actual levels of vesting. Charges are not adjusted for market related conditions which are not achieved. Where equity instruments are granted to persons other than directors or employees, the consolidated income statement is charged with the fair value of any goods or services received.

Impairment of oil and gas exploration assets

Exploration/appraisal assets are reviewed regularly for indicators of impairment following the guidance in IFRS 6 'Exploration for and Evaluation of Mineral Resources' and tested for impairment where such indicators exist. Any impairment arising is recognised in the Income Statement for the year.

Impairment reviews on development/producing assets are carried out on each cash-generating unit identified in accordance with IAS 36 'Impairment of Assets'. Ascent's cash generating units are those assets which generate largely independent cash flows and are normally, but not always, single development areas.

At each reporting date where there are indicators of impairment the net book value of the cash generating unit is compared with the measurable recoverable amount, which is defined as the higher of fair value less costs to sell or value in use. If the net book value is higher, then the difference is written off to the Income Statement as impairment. Forecast production profiles are determined on an asset-by-asset basis using appropriate petroleum engineering techniques.

Where there has been a charge for impairment in an earlier period, that charge will be reversed in a later period where there has been a change in circumstances to the extent that the discounted future net cash flows are higher than the net book value at the time. In reversing impairment losses, the carrying amount of the asset will be increased to the lower of its original carrying value or the carrying value that would have been determined (net of depletion) had no impairment loss been recognised in prior periods. 

Impairment of developed oil and gas assets

When events or changes in circumstances indicate that the carrying amount of expenditure attributable to a successful well may not be recoverable from future net revenues from oil and gas reserves attributable to that well, a comparison between the net book value of the cost attributable to that well and the discounted future cash flows from that well is undertaken. To the extent that the carrying amount exceeds the recoverable amount, the cost attributable to that well is written down to its recoverable amount and charged as an impairment.

Depletion of developed oil and gas assets

Costs carried in each well are depreciated on a unit of production basis using the ratio of oil and gas production in the period to the estimated quantity of commercial proven and probable oil and gas reserves at the end of the period plus production in the period. Costs in the unit of production calculation include the net book value of capitalised costs plus estimated future development costs.

Changes in estimates of commercial proven and probable oil and gas reserves or future development costs are dealt with prospectively.

Decommissioning costs

Where a material liability for the removal of production facilities and site restoration at the end of the field life exists, a provision for decommissioning is recognised. The amount recognised is the net present value of estimated future expenditure determined in accordance with local conditions and requirements. An asset of an amount equivalent to the provision is also added to oil and gas exploration assets and depreciated on a unit of production basis. Changes in estimates are recognised prospectively, with corresponding adjustments to the provision and the associated asset.

Property, plant and equipment assets other than oil and gas assets

Property, plant and equipment other than oil and gas assets are stated at cost, less accumulated depreciation, and any provision for impairment. Depreciation is provided at rates estimated to write off the cost, less estimated residual value of each asset over its expected useful life as follows:

Computer and office equipment - 33% straight line.

Revenue recognition

Oil and gas sales revenue is measured at the fair value of the consideration received or receivable and represents amounts receivable for the Group's share of oil and gas supplied in the period.

Inventories

Inventories, including materials, equipment and inventories of gas and oil held for sale in the ordinary course of business, are stated at weighted average historical costs, less provision for deterioration and obsolescence or, if lower, net realisable value.

Foreign currency

The Group's strategy is focused on developing oil and gas projects across Europe funded by shareholder equity and other financial assets which are principally denominated in Sterling. The functional currency of the Company is Sterling.

Transactions in foreign currency are translated to the respective functional currency of the Group entity at the rates of exchange prevailing on the dates of the transactions. At each balance sheet date, monetary assets and liabilities that are denominated in foreign currencies are retranslated to the functional currency at the rates prevailing on the balance sheet date. Exchange gains and losses on short-term foreign currency borrowings and deposits are included with net interest payable.

The assets and liabilities of foreign operations, including fair value adjustments arising on consolidation, are translated to Sterling at foreign exchange rates ruling at the balance sheet date. The revenues and expenses of foreign operations are translated to Sterling at the average rate ruling during the period. Foreign exchange differences arising on retranslation are recognised directly in a separate component of equity. They are released into the income statement upon disposal.

On consolidation, the results of overseas operations are translated into sterling at rates approximating to those ruling when the transactions took place. All assets and liabilities of overseas operations, including goodwill arising on the acquisition of those operations, are translated at the rate ruling at the reporting date. Exchange differences arising on translating the opening net assets at opening rate and the results of overseas operations at actual rate are recognised in other comprehensive income and accumulated in the foreign exchange reserve.

On disposal of a foreign operation, the cumulative exchange differences recognised in the foreign exchange reserve relating to that operation up to the date of disposal are transferred to the consolidated statement of comprehensive income as part of the profit or loss on disposal.

Exchange differences on all other transactions, except relevant foreign currency loans, are taken to operating loss.

Taxation

The tax expense represents the sum of the tax currently payable and any deferred tax.

The tax currently payable is based on the estimated taxable profit for the period. Taxable profit differs from net profit as reported in the income statement because it excludes items of income or expense that are taxable or deductible in other years and it further excludes items that are never taxable or deductible. The Group's liability for current tax is calculated using the expected tax rate applicable to annual earnings.

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities for financial reporting purposes and the corresponding tax bases used in the computation of taxable profit. It is accounted for using the balance sheet liability method. Deferred tax liabilities are 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. The carrying amount of deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow all or part of the asset to be recovered.

Equity-settled share-based payments

The cost of providing share-based payments to employees is charged to the income statement over the vesting period of the related share options or share allocations. The cost is based on the fair values of the options and shares allocated determined using the Binomial method. The value of the charge is adjusted to reflect expected and actual levels of vesting. Charges are not adjusted for market related conditions which are not achieved. Where equity instruments are granted to persons other than directors or employees, the consolidated income statement is charged with the fair value of any goods or services received.

Provisions

A provision is recognised in the balance sheet when the Group has a present legal or constructive obligation as a result of a past event, and it is probable that an outflow of economic benefits will be required to settle the obligation. If the effect is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the liability.

Convertible loan notes

Upon issue of a convertible loan where the convertible option is at a fixed rate, the net proceeds received from the issue of convertible loan notes are split between a liability element and an equity component at the date of issue. The fair value of the liability component is estimated using the prevailing market interest rate for similar non-convertible debt. The difference between the proceeds of issue of the convertible loan notes and the fair value assigned to the liability component, representing the embedded option to convert the liability into equity of the Group, is included in equity and is not re-measured.

Subsequent to the initial requisition the liability component is measured at amortised cost using the effective interest method.

Non-derivative financial instruments

Non-derivative financial instruments comprise of investments in equity and debt securities, trade and other receivables, cash and cash equivalents, loans and borrowings and trade and other payables.

Financial instruments

Financial assets and financial liabilities are recognised on the balance sheet when the Group becomes a party to the contractual provisions of the instrument.

Investments classified as held-for-trading are revalued at each balance sheet date. Trading investments are initially measured at fair value, including transaction costs. At subsequent reporting dates trading investments are measured at fair value or at cost where fair value is not readily ascertainable. Gains and losses arising from changes in fair value are recognised directly to the income statement.

Trade and other receivables are measured at initial recognition at fair value, and are subsequently measured at amortised cost using the effective interest method. A provision is established when there is objective evidence that the Group will not be able to collect all amounts due. The amount of any provision is recognised in the income statement.

Cash and cash equivalents comprise cash held by the Group and short-term bank deposits with an original maturity of three months or less.

Trade and other payables are initially measured at fair value and are subsequently measured at amortised cost, using the effective interest rate method.

Financial liabilities and equity instruments issued by the Group are classified in accordance with the substance of the contractual arrangements entered into and the definitions of a financial liability and an equity instrument. Equity instruments issued by the Company are recorded at the proceeds received, net of direct issue costs.

Interest bearing bank loans, overdrafts and other loans are recorded at fair value less any directly attributable costs, with subsequent measurement at amortised cost. Finance costs are accounted for on an accruals basis in the income statement using the effective interest method.

Equity

Equity instruments issued by the Company are recorded at the proceeds received, net of any direct issue costs.

Investments and loans

Shares and loans in subsidiary undertakings are shown at cost. Provisions are made for any permanent diminution in value when the fair value of the assets is assessed as less than the carrying amount of the asset.

Pension costs

Contributions are made to the individual pension scheme of a director's choice and are charged to the Income Statement as they become payable.

Segment 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 has been identified as the management team including the Managing Director ("MD") and the Finance Director.

The Group has five reportable segments, as described below, which are based on the geographical area that the Group activities are carried out. Each area is then subdivided into a number of different sites based on the locations of the wells. The operations and day to day running of the business is carried out on a local level and therefore managed separately. In addition, each site has different technological requirements based on their stage of development which are coordinated based on their geographical location. Each operating segment reports to the UK head office who evaluate the segments performance, decide how to allocate resources and make other operating decisions such as the purchase of material capital assets and services. Internal reports are generated and submitted to the Group's Managing Director for review on a monthly basis.

The operations of the Group as a whole are the exploration for, development and production of oil and gas reserves.

The five geographic reporting segments are made up as follows:

Italy - exploration and development

Hungary - production and exploration

Slovenia - exploration and development

Other Europe - exploration and development

(2010 the Netherlands, 2009 the Netherlands and Switzerland)

UK - head office

The cost of exploration and development works are carried out under shared licences with joint ventures and associated companies which are co-ordinated by the UK head office. Transfer prices between segments are set on an arm's length basis in a manner similar to transactions with third parties. Segment revenue, segment expense and segment results include transfers between segments. Those transfers are eliminated on consolidation.

Information regarding the results of each reportable segment is included below. Initial performance is measured by the results that arise from the exploration and development works carried out. Once producing, other production performance measures are based on the production revenues achieved. This is reported to the Group's MD by the level of capitalised exploration costs and the results from studies carried out at the individual locations of the wells. The MD uses these measures to evaluate project viability within each operating segment.