RPT.L Regulatory News (RPT)

1 April 2014

REGAL PETROLEUM PLC

2013 AUDITED RESULTS

Regal Petroleum plc (the "Company", and with its subsidiaries, the "Group"), the AIM-quoted (RPT) oil and gas exploration and production group, today announces its audited results for the year ended 31 December 2013.

Principal Developments

Ukraine Operations

· Despite current events in Ukraine, the Group has been able to operate normally, although the change of Government has resulted in volatility in the Ukrainian Hryvnia exchange rates and uncertainty in the gas sales price

· Average production over the year to 31 December 2013 of 185,677 m3/d of gas and 42 m3/d of condensate (1,422 boepd in aggregate) compared to 2012: 201,002 m3/d of gas and 45 m3/d of condensate (1,539 boepd in aggregate)

· Well SV-59 on production testing since January 2014, but wells MEX-105 and SV-53 unsuccessful

· Upgrade of gas processing facility to improve efficiency and quality of gas produced and provide for recovery of LPG completed

· Average LPG production of 20 m3/d from 1 January 2014 to 30 March 2014, providing new revenue stream

· Independent report commissioned to assess the Group's Reserves and Resources as at 31 December 2013 resulting in a reduction in Proved + Probable (2P) remaining Reserves from 31.6 MMboe to 11.7 MMboe

Finance

· Revenue for the year from continuing operations of $36.7 million (2012: $41.1 million)

· Loss for the year from continuing operations of $127.2 million (2012: $13.0 million profit), principally due to impairment loss of $159.2 million (2012: $nil) on the Group's oil and gas development and producing asset in Ukraine

· Cash generated from operations of $26.5 million (2012: $33.1 million)

· Average realised 2013 gas and condensate prices in Ukraine of $415/Mm3 and $91/bbl respectively (2012: $420/Mm3 and $99/bbl respectively)

· Cash and cash equivalents at 31 December 2013 of $25.1 million (31 December 2012: $28.5 million), with cash balance at 30 March 2014 of $24.0 million

 Outlook

· Focus on continued geophysical studies to improve understanding of the sub-surface at MEX-GOL and SV fields

· Plan to commence drilling of MEX-109 well, workover of SV-61 well and undertake hydraulic fracturing of MEX-120 and MEX-105 wells

· Funding of planned 2014 development programme anticipated to be from existing cash and cash equivalents and operational revenues

The Annual Report and Accounts for 2013, together with the Notice of Annual General Meeting, will be posted to shareholders and published on the Company's website during April 2014.

For further information, please contact:

Joe Staffurth, BSc Geology, PESGB, AAPG, consultant to the Company, has reviewed and approved the technical information contained within this press release in his capacity as a qualified person, as required under the AIM Rules.

Definitions

AAPG American Association of Petroleum Geologists

bbl barrel

boe barrels of oil equivalent

Bscf thousands of millions of standard cubic feet

boepd barrels of oil equivalent per day

GIIP gas initially in place

HSES health, safety, environment and security

km kilometres

km2 square kilometres

LPG liquefied petroleum gas

m3 cubic metre

m³/d cubic metres per day

Mm³ thousand cubic metres

Mtonnes thousand tonnes

MMbbl million barrels

MMboe million barrels of oil equivalent

% per cent

scf standard cubic feet measured at 14.7 pounds per square inch and 60 degrees Fahrenheit

SPE Society of Petroleum Engineers

SPEE Society of Petroleum Evaluation Engineers

$ United States Dollar

c United States Cent

UAH Ukrainian Hryvnia

WPC World Petroleum Council

Chairman's Review

The Group is continuing with the development of our 100% owned and operated Mekhediviska-Golotvshinska ("MEX-GOL") and Svyrydivske ("SV") gas and condensate fields in Ukraine. I am pleased to be able to report we continued to operate safely during the period, with no Lost Time Incidents or Restricted Work Cases.

The major events that have taken place in Ukraine during recent months, including the change of Government, have meant that there has been a great deal of uncertainty about the political and economic outlook in Ukraine.

Despite the upheaval, the Group has been able to operate normally, although the change of Government has resulted in volatility in the Ukrainian Hryvnia exchange rates and uncertainty in our realised gas sales price in Ukraine. The internal gas price is generally related to the imported price of gas from Russia, but the previous Government had negotiated a significant discount to the imported gas price. This resulted in a reduction in the internal gas price during the first quarter of 2014, but the Ukrainian authorities have announced that the internal gas price will be increased with effect from 1 April 2014. 

As regards the Group's financial performance, a substantial loss was recorded in 2013, primarily as a result of the reduction in the value in use, and consequent impairment loss relating to the Group's oil and gas development and producing asset in Ukraine. However cash generated from operations was positive at $26.5 million (2012: $33.1 million).

An updated assessment of our remaining Reserves and Contingent Resources attributable to the Group's MEX-GOL and SV fields, as at 31 December 2013, was announced on 25 March 2014. In summary, the Proved (1P) Reserves reduced from 7.7 MMboe to 1.9 MMboe and the Proved and Probable (2P) Reserves reduced from 31.6 MMboe to 11.7 MMboe. This reduction in Reserves resulted in the recognition of the impairment loss, and is explained in more detail in the Operations Review below.

Operationally during 2013, we undertook a capital investment programme at our Ukrainian fields, which involved completing the drilling and/or testing of three new wells, undertaking well workover and hydraulic fracturing operations, upgrading the gas processing facility, installing LPG recovery equipment, upgrading methanol facilities and installing compression equipment. 

We completed the hook-up and testing of the SV-53 and MEX-105 wells during the first half of 2013, but unfortunately neither well delivered the anticipated levels of production. The SV-53 well did produce at modest rates, using compression, and underwent a hydraulic fracturing programme but this programme did not improve flow rates, and the well has now ceased producing. The MEX-105 well did not produce hydrocarbons on test and has undergone a well stimulation programme, which included hydraulic jet perforation, but this programme was unsuccessful, and accordingly a hydraulic fracturing programme is being developed to be carried out during 2014.

In the second half of the year, drilling of the SV-59 well was completed and after initial testing, the well was hooked up to the gas processing facility and its performance was monitored during a production testing programme. Flow rates averaged approximately 10,700 m3/d of gas and 15 m3/d of condensate (158 boepd in aggregate) during the production testing period, and the well continues to produce at similar flow rates.

The upgrades to the Group's gas processing facility, designed to improve the facility's overall efficiency, incorporate compression equipment, provide for LPG recovery and stabilise condensate production, have been completed, as has the upgrade of methanol equipment at two existing wells and the installation of compression equipment in the field. 

With the installation of the LPG recovery equipment, production of LPG commenced at the very end of 2013, and for the period from 1 January 2014 to 30 March 2014, LPG production rates have averaged 20 m3/d (87 boepd).

The Group continues to be supported by Energees Management Limited ("Energees"; part of the Smart Holding Group "Smart"), which has maintained its 54% shareholding in the Company's issued share capital and continues its support of the Group and its operations in Ukraine.

Business Review and Outlook

In light of the mixed results from the new wells, the Group is undertaking further geophysical studies and has revised its field development plan to reduce the number of new wells and to slow the phasing of its drilling programme. The revision of the field development plan has resulted in a reduction of both the Reserves and the carrying value of the Group's oil and gas development and producing asset in Ukraine, and a consequent impairment charge in the accounts for the year ended 31 December 2013.

Our focus during 2014 will be to continue the geophysical studies to improve our understanding of the sub-surface within our licences, as well as commencing the drilling of the MEX-109 well, working over the SV-61 well and undertaking hydraulic fracturing of the MEX-120 and MEX-105 wells. Successful completion of these activities, together with continuing analysis of our geological and geophysical data to provide a better understanding of the MEX-GOL and SV reservoirs and their performance, is expected to ultimately help enable us to improve our daily production.

The upgrades to our gas processing facility have improved the efficiency of our gas processing and production, improved the quality of the gas produced and enabled us to recover and sell LPG. Based on our current production, and the resultant revenue we receive for our gas, condensate and LPG sales, we anticipate that our planned 2014 development programme will be funded from existing cash and cash equivalents and operational revenues.

In conclusion, on behalf of the Board, I would like to thank our staff for the continued dedication and support they have shown, particularly during the difficult events in Ukraine over recent months. 

Keith Henry

Executive Chairman

Operations Review

Health, Safety, Environment and Security ("HSES")

The Group is committed to maintaining the highest standards of HSES and the effective management of these areas is an intrinsic element of the overall business ethos. Through strict enforcement of the Group's HSES Management System, together with regular management meetings, training and the appointment of dedicated safety professionals, the Group strives to ensure that the impact of its business activities on its staff, contractors and the environment is as low as is reasonably practicable. The Group reports safety and environmental performance in accordance with industry practice and guidelines.

During 2013, the Group continued to operate safely and did not experience any Lost Time Incidents or Restricted Work Cases.

Ukraine Operations

Asset Overview

Regal Petroleum Corporation Limited (a wholly owned subsidiary in the Group) holds a 100% working interest and is the operator of the MEX-GOL and SV fields. The licences are the Group's sole assets and extend over a combined area of 269 km², approximately 200 km east of Kiev. The two licences are adjacent and the interests are operated and managed as one field.

The fields are located, geologically, towards the middle of the Dnieper-Donets sedimentary basin which extends across the majority of north-east Ukraine. The vast majority of Ukrainian gas and condensate production comes from this basin. The reservoir comprises a series of gently dipping Carboniferous sandstones of Visean age ("B-Sands") inter-bedded with shales that form stratigraphic traps at around 4,700 metres below the surface, with a gross thickness between 800 metres and 1,000 metres. Analysis suggests that these deposits range from fluvial to deltaic in origin. Below these reservoirs is a thick sequence of shale above deeper, similar, sandstones which are encountered at a depth of around 5,800 metres. These sands are of Tournasian age ("T-Sands"). Deeper sandstones of Devonian age ("D-Sands") have also been penetrated in the fields.

Production

The Group's average production over the year ended 31 December 2013 was 185,677 m³/d of gas and 42 m³/d of condensate, which equates to a combined total oil equivalent of 1,422 boepd. 

The Group's average production for the period from 1 January 2014 to 30 March 2014 was 156,335 m³/d of gas and 55 m³/d of condensate, which equates to a combined total oil equivalent of 1,321 boepd. 

With the installation of the LPG recovery equipment, production of LPG commenced at the very end of 2013, and for the period from 1 January 2014 to 30 March 2014, LPG production rates have averaged 20 m3/d (87 boepd).

Operations

The SV-53 and MEX-105 wells, which were spudded in February 2012 and April 2012 respectively, were completed and tested during the first half of 2013, and another new well, SV-59, was spudded in February 2013. The objective of all three wells was the B-Sands. The new wells were drilled by local Ukrainian drilling contractors, with the Ukrainian drilling rigs being supplemented by the use of selected western technology and equipment designed to improve the efficiency of drilling operations. 

Well SV-53 reached its target depth of 5,450 metres in October 2012. The well was hooked up to the gas processing facility in mid-January 2013, and production testing was undertaken using a variety of choke sizes and operating modes. Although initial flow rates were encouraging, they declined very significantly over the testing period. Compression equipment was utilised for a period, before a hydraulic fracturing programme was undertaken on the well in the fourth quarter of 2013 but unfortunately this did not increase flow rates and the well has ceased producing. It is believed that these results reflect the penetration of good quality reservoir sands but of limited lateral extent and volume.

Well MEX-105 reached a depth of 5,228 metres in February 2013. Drilling was terminated 22 metres short of its original target depth as all targeted B-Sands formations had been encountered. The well underwent a production testing programme during the first half of 2013 but did not produce hydrocarbons on test and has undergone a well stimulation programme, which included hydraulic jet perforation, but this programme was unsuccessful. As a result, a hydraulic fracturing programme is being developed to be carried out during 2014.

Well SV-59 was drilled to a depth of 5,470 metres, completed and, after initial testing, hooked up to the gas processing facility in early 2014. Its performance was monitored during a production testing programme, during which flow rates averaged approximately 10,700 m3/d of gas and 15 m3/d of condensate (158 boepd in aggregate), and the well continues to produce at similar flow rates.

A two-phased workover on the GOL-1 well, designed to eliminate the ingress of water was undertaken, but unfortunately, these operations proved unsuccessful and as a result, it has not been possible to bring this well back on production. No further intervention operations are currently planned at this well.

The MEX-120 well, which was intermittently producing small volumes of hydrocarbons, underwent a hydraulic fracturing programme in February 2014, but unfortunately this programme was suspended after equipment failure. It is intended to conclude the programme later in 2014.

The upgrades to the Group's gas processing facility, designed to improve the facility's overall efficiency, incorporate compression equipment, provide for LPG recovery and stabilise condensate production, have been completed, as has the upgrade of methanol equipment at two existing wells and the installation of compression equipment in the field. 

2014 Reserves Report

As a result of the mixed results from the new wells on the MEX-GOL and SV licence areas, the Group decided to undertake further geophysical studies in order to improve the understanding of the sub-surface at such licence areas, and to reduce the number and slow the phasing of its new well drilling programme. 

In light of the revision of the current field development plan to reduce and slow the well drilling programme, the Group considered it appropriate to undertake a re-assessment of the Reserves and Resources at the MEX-GOL and SV licence areas.

Accordingly, the Group engaged independent petroleum consultants, ERC Equipoise Limited ("ERCE"), to prepare an updated assessment of the remaining Reserves and Contingent Resources attributable to the Group's MEX-GOL and SV fields as at 31 December 2013 (the "ERCE Report").

The ERCE Report, announced on 25 March 2014, is consistent with the Group's revised field development plans, which comprise the drilling of a further 10 wells, and accords with the March 2007 SPE/WPC/AAPG/SPEE Petroleum Resources Management System standard for classification and reporting.

The ERCE Report estimated the remaining Reserves as at 31 December 2013 in the Visean B-Sands reservoirs of the MEX-GOL and SV fields as follows:-

The ERCE Report estimated the Contingent Resources in the Visean B-Sands reservoirs of the MEX-GOL and SV fields as follows, based on the potential drilling of up to 113 future wells (not currently budgeted):-

The ERCE Report provides an update on the Group's Reserves and Resources since the previous Reserves estimation undertaken by ERCE as at 31 December 2012 and takes into account information gathered during the drilling of additional wells in the fields since then. The Gas Initially In Place ("GIIP") assessment in the ERCE Report remains the same as previously, demonstrating discovered GIIP in the B-Sands reservoirs of 5816 Bscf, but there has been a material reduction in the Proved (1P) and Proved + Probable (2P) categories of remaining Reserves from the previous ERCE estimates which were 7.7 MMboe and 31.6 MMboe respectively. These reductions reflect a reduction in the number (from 27 to 10) and slowing of the phasing of new wells, production since 1 January 2013 of approximately 0.52 MMboe and the down-grading of a portion of volumes previously booked as Reserves into the Contingent Resources category, reflecting their current immaturity for commercial development. Further evaluation and development of the fields may result in future movement between Contingent Resources and Reserves. 

In its Report, ERCE has estimated volumes of discovered gas totalling 1944 Bscf in the deeper T-Sands and D-Sands intervals, but has concluded that there is insufficient information at this time to determine whether the discovered gas is recoverable or not, and hence no Reserves or Contingent Resources have been assigned to these formations. Accordingly, all Reserves and Contingent Resources assessed in the ERCE Report are within the B-Sands reservoirs.

Finance Review

The Group's loss from continuing operations for the year ended 31 December 2013 was $127.2 million (2012: $13.0 million profit). This is principally due to the impairment loss of $159.2 million (2012: $nil) on the Group's oil and gas development and producing asset in Ukraine resulting from the revision of the Group's field development plan and the reduction in Reserves and Resources referred to above. The Group's oil and gas development and producing asset in Ukraine was tested for impairment, and in determining the value in use of such asset, a number of assumptions were made. This testing has demonstrated that the residual carrying value of $72.9 million is particularly sensitive to future changes in the gas price and assumptions on discount rate, production levels and successful extension of the production licences until the end of the economic life of the fields, all of which are discussed in more detail in Note 4.

Revenue from continuing operations, derived from the sale of the Group's Ukrainian gas and condensate production, was $36.7 million (2012: $41.1 million) due to a combination of lower volumes and lower average prices.

Cash generated from operations was positive at $26.5 million (2012: $33.1 million).

For the year ended 31 December 2013, the average realised gas and condensate prices were $415/Mm3 (UAH3,380/Mm3) and $91/bbl respectively (2012: $420/Mm3 and $99/bbl respectively). 

From 1 January 2014, our average realised gas price reduced to $339/Mm3 (UAH3,051/Mm3) resulting from negotiations between Russia and Ukraine over the imported gas price. The maximum internal gas prices within Ukraine are set quarterly by the National Electricity Regulatory Commission ("NERC") and are generally related to the imported price of gas from Russia. The Group's realised gas price is close to the maximum internal gas price set by NERC. In December 2013, the previous Government of Ukraine negotiated a significant discount to the imported gas price calculated under the longstanding agreement between Russia and Ukraine. However, following the recent change of Government, Russian officials have stated that the discount of the imported gas price is to be reconsidered, and as a consequence, it seems probable that the imported gas price will revert to the price calculated under the longstanding agreement between Russia and Ukraine.

It has been announced by NERC that, with effect from 1 April 2014, the internal gas price will increase to $363/Mm3 (UAH4,020/Mm3 using the exchange rate at 31 March 2014 of UAH11.09/$1.00) for the second quarter of 2014.

The completion of the upgrade to the gas processing facility in late December 2013 to enable recovery of LPG has provided a new revenue stream, and our average realised price for LPG from 1 January 2014 was $440/m3.

Cost of sales for the year ended 31 December 2013 was $33.7 million (2012: $21.4 million). This increase was due to a combination of higher depreciation charges of $17.3 million (2012: $11.0 million) due to the revised Reserves base as at 31 December 2013, the new single subsoil tax charge of $7.2 million (2012: $6.1 million), which came into effect from 1 January 2013 and replaced the previous royalty and subsoil tax regime, and a write down of inventory of $3.0 million (2012: $0.7 million). The Ukrainian authorities have announced that the rates for the single subsoil tax are to be increased in the near future.

Included within finance costs, is a charge for the discounting of long-term purchase tax recoverable from the Ukrainian Government of $0.1 million (2012: finance income from the unwinding of the discount of $2.5 million) due to an increase in the forecast recovery period related to the revised well drilling programme.

The tax credit for the period of $35.8 million (2012: charge of $0.1 million) comprises a current tax charge of $1.5 million (2012: charge of $1.7 million) and a deferred tax credit of $37.3 million (2012: credit of $1.6 million). $32.7 million of the deferred tax credit is due to the impairment loss relating to the Group's oil and gas development and producing asset, which has resulted in the carrying value of the asset being significantly lower than its tax base. This has resulted in a reversal of the prior year deferred tax liability and the recognition of a deferred tax asset of $28.6 million deemed recoverable against future taxable profits in Ukraine. However, should future field development not result in additional production, only approximately $3 million of the deferred tax asset would be recovered, as discussed in more detail in Note 5. The remaining $4.6 million credit is a result of the recognition of previously unrecognised tax losses in the Company, which are projected to be utilised against forecast future profits derived from interest on intra-group loans.

Capital investment in the Group's oil and gas development and producing asset for the period was $23.5 million (2012: $19.2 million) which principally reflects the 2013 drilling programme and upgrades to the gas processing facilities in Ukraine.

Cash and cash equivalents held at 31 December 2013 were $25.1 million (31 December 2012: $28.5 million). The Group's cash and cash equivalents balance at 30 March 2014 was $24.0 million. The movement since 31 December 2013 reflects operational cash generated since that date less capital investment in the asset.

Cash from operations has funded the capital investment during the 2013 year, and the Group's current cash position and positive operating cash flow are the sources from which the Group expects the 2014 capital investment programme will be funded.

With effect from 1 January 2013, the functional currency of two of the Group's Ukrainian subsidiaries has changed from US Dollars to Ukrainian Hryvnia. The change was triggered by the increasing influence of the Ukrainian Hryvnia on the subsidiaries' operations, compared to the prior year. Whilst historically, the majority of the development costs were influenced by US Dollars and Euros, more recently these costs have been predominantly in Ukrainian Hryvnia. In addition, the maximum internal gas price in Ukraine set by NERC, and hence the Group's revenues, have been less influenced by the US Dollar. 

The Interim Report announced on 24 September 2013 used US Dollars as the functional currency of these two Ukrainian subsidiaries. As a result, the carrying value of the Group's oil and gas development and producing asset in Ukraine, and also the foreign exchange reserve in equity, were overstated by $4.2 million.

The reporting currency of the Group will remain US Dollars.

The recent events in Ukraine have resulted in a significant devaluation of the Ukrainian Hryvnia against the US Dollar, which is likely to affect the carrying value of the Group's assets in the future. 

Operational Environment, Principal Risks and Uncertainties

The Group has a risk evaluation methodology in place to assist in the review of the risks across all material aspects of its business. This methodology highlights technical, operational, external and fiduciary risks and assesses the level of risk and potential consequences. It is periodically presented to the Audit Committee and the Board for review, to bring to their attention potential concerns and, where possible, propose mitigating actions. Key risks recognised are detailed below:

Risks relating to Ukraine

Since November 2013, Ukraine has been subject to political unrest. On 22 February 2014, the Parliament of Ukraine voted for a reinstatement of the 2004 Constitution and dismissal of the incumbent President. New presidential elections are scheduled for May 2014 and a transitional Government has been formed. On 27 February 2014, pro-Russian factions took control of the parliament of Crimea, an autonomous region of Ukraine, which then voted to hold a referendum on the status of Crimea in March 2014. Following this referendum, Crimea was effectively annexed by the Russian Federation. The Group has no assets in Crimea, nor do its operations rely on sales or costs incurred there.

During 2014, the Ukrainian Hryvnia has devalued against major world currencies and significant external financing is required to maintain the country's economic stability. The National Bank of Ukraine, among other measures, has imposed temporary restrictions on the processing of client payments by banks and on the purchase of foreign currency on the inter-bank market. In February 2014, Ukraine's sovereign rating was downgraded to CCC with a negative outlook. The impact of the escalation of the crisis in Ukraine-Russia relations and its final resolution are unpredictable and are likely to adversely affect the Ukrainian economy.

These events have not affected the Group's operations to date, but further escalations of the political crisis may impact the Group's normal business activities, and increase the risks relating to its business operations, financial status and maintenance of its Ukrainian production licences.

The Ukrainian Government is keen to develop the country's domestic production of hydrocarbons since Ukraine imports the majority of its gas needs from Russia. Whilst this should put the Group in a well-placed position, as experienced previously, there are significant risks to carrying out business in the country. It is considered that the involvement of Energees, as a major shareholder with extensive experience in Ukraine, has helped to mitigate such risks.

Production risks

Producing gas and condensate reservoirs are generally characterised by declining production rates which vary depending upon reservoir characteristics and other factors. Future production of the Group's gas and condensate reserves, and therefore the Group's cash flow and income, are highly dependent on the Group's success in operating existing producing wells, drilling new production wells and efficiently developing and exploiting any reserves, and finding or acquiring additional reserves. The Group may not be able to develop, find or acquire reserves at acceptable costs. The experience gained from drilling undertaken to date highlights such risks as the Group targets the appraisal and production of these hydrocarbons.

Risks relating to further development and operation of the Group's gas and condensate fields in Ukraine

The planned development and operation of the Group's gas and condensate fields in Ukraine is susceptible to appraisal, development and operational risk. This could include, but is not restricted to, delays in delivery of equipment in Ukraine, failure of key equipment, lower than expected production from wells that are currently producing, or new wells that are brought on-stream, problematic wells and complex geology which is difficult to drill or interpret. The generation of significant operational cash is dependent on the successful delivery and completion of the development and operation of the fields. These risks have been demonstrated by the downgrade in the Group's remaining reserves which has resulted in the reduction in the value in use, and consequent impairment loss relating to the Group's oil and gas development and producing asset in Ukraine. Furthermore, the optimisation of all of the Group's assets is dependent on maintaining constructive relationships between all business stakeholders.

Exposure to credit, liquidity and cash flow risk

The Group does not currently have any loans outstanding. Local customers are managed in Ukraine and their financial position, past experience and other factors are evaluated. Internal financial projections are regularly made based on the latest estimates available, and various scenarios are run to assess the robustness of the liquidity of the Group. The Group currently holds sufficient cash and cash equivalents for the anticipated short to medium term needs of the business. Whilst much of the future capital requirement is expected to be derived from operational cash generated from production, including from wells yet to be drilled, there is a risk that in the longer term insufficient operational cash is generated, or that additional funding, should the need arise, cannot be secured.

Currency risk

The Group's main activities are (i) investment into the development of the Group's Ukrainian gas and condensate asset; (ii) the production and sale of gas, condensate and LPG; and (iii) the continued exploration for further hydrocarbon reserves.

The Group receives sales proceeds in Ukrainian Hryvnia, and the majority of the capital expenditure costs for the 2014 investment programme will be incurred in Hryvnia, thus revenue and costs are largely matched. As with all currencies, the value of the Hryvnia is subject to foreign exchange fluctuations. Currently the Hryvnia does not benefit from the range of currency hedging instruments which are available in more developed economies and, as a result, the Group has adopted a policy that funds not required for use in Ukraine be retained on deposit in the United Kingdom, principally in US Dollars.

During 2014, the Ukrainian Hryvnia has devalued against major world currencies and significant external financing is required to maintain the country's economic stability. The National Bank of Ukraine, among other measures, has imposed temporary restrictions on the processing of client payments by banks and on the purchase of foreign currency on the inter-bank market. In February 2014, Ukraine's sovereign rating was downgraded to CCC with a negative outlook. In addition, the recent events in Ukraine, as outlined above in "Risks relating to Ukraine", are likely to continue to impact the valuation of the Ukrainian Hryvnia against major world currencies. In addition, further devaluation of the Ukrainian Hryvnia against the US Dollar will affect the carrying value of the Group's assets. 

Ukraine Production Licences

The Group operates in a region where the right to production can be challenged by State and non-State parties. During 2010, this manifested itself in the form of a Ministry Order instructing the Group to suspend all operations and production from its Ukrainian production licences. Whilst the Ministry Order has now been resolved, the environment is such that a challenge may arise at any time in the future in relation to the Group's operations, licence history, compliance with licence commitments and/or local regulations. The Group endeavours to ensure compliance with commitments and regulations via Group procedures and controls or, where this is not immediately feasible for practical or logistical considerations, seeks to enter into dialogue with the relevant Government bodies with a view to agreeing a reasonable timeframe for achieving compliance or an alternative, mutually agreeable course of action.

The Group's production licences for the MEX-GOL and SV field currently expire in 2024. However, in the estimation of its reserves, it is assumed that the field development will continue until the end of the field's economic life in 2036, and a consequent assumption is made that licence extensions will be granted in accordance with current Ukrainian legislation. Despite such legislation, it is possible that licence extensions will not be granted which would affect the achievement of full economic field development and consequently the carrying value of the Group's oil and gas development and producing asset in the future.

Hydrocarbon price risk

The Group derives its revenue principally from the sale of its Ukrainian gas, condensate and LPG production. These revenues are subject to commodity price volatility and political influence. A prolonged period of low gas, condensate and LPG prices may impact the Group's ability to maintain its long-term investment programme with a consequent effect on growth rate which in turn may impact the share price or any shareholder returns. Lower gas, condensate and LPG prices may not only decrease the Group's revenues per unit, but may also reduce the amount of gas, condensate and LPG which the Group can produce economically, as would increases in costs associated with hydrocarbon production, such as subsoil taxes and royalties.

Recently, there has been significant uncertainty about the future gas price in Ukraine, which has been exacerbated by the major political events that have taken place in Ukraine during recent months. The internal gas price has been generally related to the imported price of gas from Russia, but in December 2013, the previous Government of Ukraine negotiated a significant discount to the imported gas price calculated under the longstanding agreement between Russia and Ukraine, which was expected to result in a reduction in the internal gas price during 2014. However, following the recent change of Government, Russian officials have stated that the discount of the imported gas price is to be reconsidered, in which case it seems likely that the imported gas price will revert to the price calculated under the longstanding agreement between Russia and Ukraine, which is likely to be higher over the immediate future. As a result of the continuing uncertainty regarding the internal gas price, it should be recognised that the internal gas price may increase or decline significantly.

The overall economics of the Group's key asset (being the net present value of the future cash flows from the Ukrainian project) are far more sensitive to long term gas, condensate and LPG prices than short term price volatility. However, short term volatility does affect liquidity risk, as, in the early stage of the project, income from production revenues is offset by capital investment.

Industry risks

The Group's ability to execute its strategy is subject to risks which are generally associated with the oil and gas industry. For example, the Group's ability to pursue and develop its projects and development programmes depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, gas, oil, condensate and LPG prices, development costs and drilling success. As a result of these uncertainties, it is unknown whether potential drilling locations identified on proposed projects will ever be drilled or whether these or any other potential drilling locations will be able to produce gas, oil or condensate. In addition, drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be discovered. Drilling for hydrocarbons can be unprofitable, not only due to dry holes, but also as a result of productive wells that do not produce sufficiently to be economic. In addition, drilling and production operations are highly technical and complex activities and may be curtailed, delayed or cancelled as a result of a variety of factors. Furthermore, whilst the Group is committed to maintaining the highest standards of health, safety, environmental and security in its operational activities, hydrocarbon drilling and production operations carry inherent risks, which in the event of an incident may significantly affect the operational, production, financial and/or business activities of the Group.

Financial Markets and Economic Outlook

The performance of the Group will be influenced by global economic conditions and, in particular, the conditions prevailing in the United Kingdom and Ukraine. The economies in these regions have been subject to volatile pressures during the period, with the global economy having experienced a long period of difficulties, and more particularly the recent events that have occurred in Ukraine. If these events continue, worsen or recur, the Group may be exposed to increased counterparty risk as a result of business failures in Ukraine or elsewhere and will continue to be exposed if counter-parties fail or are unable to meet their obligations to the Group. The precise nature of all the risks and uncertainties the Group faces as a result of these risks cannot be predicted and many of these are outside of the Group's control.

Risks relating to key personnel

The Group has a relatively small team of executives and senior management. Whilst this is sufficient for a company of this nature, there is a dependency risk relating to the loss of key individuals.

Going concern risk

The Group's business activities, together with the factors likely to affect its future development, performance and position are set out in the Business Review and Outlook section of the Chairman's Review. The financial position of the Group, its cash flows and liquidity position are described in the Finance Review. 

The Group is exposed to risks relating to Ukraine as well as production, hydrocarbon price and the other risks, as detailed in the paragraphs above. In view of this, the Group prepares monthly cash flow forecasts which take into account the risks facing the business, to assess its ability to meet its obligations as they fall due, taking into account the risks of variances in revenues.

Having reviewed the accounts, budgets and forward plans (including sensitivity analysis), the latest operational results, the risks outlined above, and having taken into account the current and recent practice of contracting for drilling services on a fixed-price basis, the absence of long term contractual arrangements relating to drilling, the assessment of well results prior to the entering into firm commitments for future drilling operations and the lower committed expenditure in Ukraine, the Directors continue to believe that the Group is well placed to manage its business risks successfully despite the current uncertain political and economic outlook. The Directors have a reasonable expectation that the Group has adequate resources to continue in operational existence for the foreseeable future. Therefore they continue to adopt the going concern basis of accounting in preparing the annual financial statements.

Consolidated Income Statement

for the year ended 31 December 2013

Consolidated Statement of Comprehensive Income

for the year ended 31 December 2013

* Prior year is restated as in 2012 the historical exchange differences reclassified on the disposal of the Group's subsidiary Regal Petroleum Romania SRL amounting to $1,168,000 should have been included in the Consolidated Statement of Comprehensive Income.

Consolidated Balance Sheet

at 31 December 2013

Consolidated Statement of Changes in Equity

at 31 December 2013

**Predominantly as a result of exchange differences on intra group loans and other retranslation, where the subsidiaries' functional currency is not US Dollar.

Consolidated Cash Flow Statement

for the year ended 31 December 2013

Notes forming part of the financial information

1. Statutory Accounts

The financial information set out above does not constitute the Company's statutory accounts for the year ended 31 December 2013 or 2012, but is derived from those accounts. The Auditor has reported on those accounts; its reports were unqualified, but did contain an emphasis of matter in 2013 in respect of the political and economic environment in Ukraine (further details are available in the Operational Environment, Principal Risks and Uncertainties section above and Note 2 below). The Auditor's Report did not contain statements under sections 498(2) or (3) of the Companies Act 2006.

The statutory accounts for 2013 will be delivered to the Registrar of Companies following the Company's Annual General Meeting.

While the financial information included in this preliminary announcement has been prepared in accordance with International Financial Reporting Standards ("IFRS"), this announcement does not itself contain sufficient information to comply with IFRS. The Company expects to distribute the full financial statements that comply with IFRS in April 2014.

2. Critical Accounting Estimates and Assumptions

The Group makes estimates and assumptions concerning the future. The resulting accounting estimates will, by definition, seldom equal the related actual results. The estimates and assumptions which have a risk of causing material adjustment to the carrying amounts of assets and liabilities within the next financial year are discussed below.

(a) Recoverability of Development and Production Assets in Ukraine

According to the Group's accounting policies, costs capitalised as assets are assessed for impairment at each balance sheet date. In assessing whether an impairment loss has occurred, the carrying value of the asset is compared to its recoverable amount, which IAS36 defines as the higher of fair value less cost to sell and value in use. Management does not believe it possible to measure fair value reliably, due to both the absence of an active market in which to sell the asset and the current political and economic climate in Ukraine. Therefore, as in previous years, management has used value in use, using a discounted cash flow model to measure its recoverable amount. This requires judgment in the following areas:

(i) Sales price - As outlined in the Finance Review and Principal Risks and Uncertainties sections above, the Ukraine gas price was significantly lower from 1 January 2014. However, it has been announced by the Ukrainian authorities that the gas price will be increased with effect from 1 April 2014. Nevertheless, there continues to be a level of uncertainty in forecasting the Ukraine gas price due to the current political and economic climate in Ukraine. The estimate used in the calculation uses the gas price realised in the first quarter of 2014.

(ii) Production levels - Management's estimate is based on a third party reserves report which relies on a combination of technical and operational data and independent reservoir interpretations.

(iii) Discount rate - Management applies a pre-tax discount rate which reflects both the time value of money and its assessment of the risk associated with development and producing oil and gas assets in Ukraine. Due to the recent events in Ukraine, there is an increased level of risk associated with operating in Ukraine, and consequently a higher discount rate has been applied.

(iv) Life of field - Management's estimate of recoverable amount is based on recovering reserves beyond the validity of its current production licences. Management believes that the current licences, which are due to expire in July 2024 will be extended under applicable legislation in Ukraine until the end of the economic life of the field, which is assessed to be June 2036. No application for such an extension has been made at the date of this announcement, however management considers the assumption to be reasonable based on its intention to seek such an extension in due course and that the Group is legally entitled to request an extension.

The impairment assessment carried out at 31 December 2013, has resulted in an impairment loss of $159 million. Further details of this assessment, including the sensitivity to the above assumptions are set out in Note 4.

(b) Decommissioning

The Group has decommissioning obligations in respect of its Ukraine asset. The full extent to which the provision is required depends on the legal requirements at the time of decommissioning, the costs and timing of any decommissioning works and the discount rate applied to such costs.

During 2013, a detailed assessment of gross decommissioning cost was undertaken on a well-by-well basis using local data on day rates and equipment costs, compared to previous years where the same cost was assumed for each well.

The decommissioning costs are estimated to be incurred by June 2036, which is the end of the economic life of the field. As outlined in (a)(iv) above, management believes that the current licences, which are due to expire in July 2024, will be extended until June 2036.

(c) Depreciation of Development and Production Assets

Development and production assets held in property, plant and equipment are depreciated on a unit of production basis at a rate calculated by reference to proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions about the number of wells required to produce those reserves, the cost of the wells, future production facilities and operating costs, together with assumptions on oil and gas realisations, and are revised annually. The reserves estimates used are determined using estimates of gas in place, recovery factors, future hydrocarbon prices and also take into consideration the Group's latest development plan for the associated development and production asset. Additionally, as outlined in (a)(iv) above, the latest development plan and therefore the inputs used to determine the depreciation charge, assume that the current licences which are due to expire in July 2024, can be extended until June 2036.

(d) Timing of recovery of purchase tax receivable

The Group has significant receivables from the State Budget of Ukraine relating to reimbursement of purchase tax arising on purchases of goods and services from external service and product providers. The Group recognises recoverable purchase tax only to the extent that it is probable that the purchase tax payable arising on the sales of gas and condensate production will be sufficient to offset the purchase tax due from the State within a reasonable period. Estimating the recoverability, net present value and classification (current asset versus non-current asset) of purchase tax receivable requires management to make an estimate of the timing of future revenues in order to calculate the amount and timing of the purchase tax payable available for offset.

(e) Recoverability of materials inventory

The majority of the Group's materials inventory balance comprises items to be used in the Ukraine drilling programme. Where there is uncertainty whether the materials will be realised through the drilling programme, or through sale, the materials are recorded at selling price, less any associated costs. Where materials inventory is intended for sale, management uses current market rates to estimate the recoverable amount through sale.

A full review of the Group's materials inventory was undertaken following the revision to the field development plan, which reduced the number and phasing of new wells in the fields from 27 to 10. The reduced drilling activity has meant that the Group has a reduced short term requirement for drilling materials. The reduction in future utilisation of this inventory, coupled with unsuccessful attempts during the year to sell unwanted items, has led to the write down of the materials inventory balance.

(f) Recognition of deferred tax asset

The recognition of deferred tax assets is based upon whether it is more likely than not that sufficient and suitable taxable profits will be available in the future against which the reversal of temporary differences can be deducted. This requires judgment for forecasting future profits.

A deferred tax asset of $7.8 million has been recognised in respect of the brought forward losses in the Company. Management believes that these can be offset against forecast future profits, which are derived from intra-group loan interest which is taxable in the UK. The forecast is limited to 5 years, beyond which management do not consider they can reliably forecast the Group funding structure and hence no deferred tax asset has been recognised in respect of losses of approximately $57 million, not anticipated to be utilised in this 5 year period.

In addition, a deferred tax asset of $28.5 million has also been recognised on the tax effect of the difference between the carrying value of the Group's oil and gas development and production asset, and its tax base. This is deemed recoverable on the projected future profits generated by the Group's operations in Ukraine. The forecast profits are based on the current field development plan, and are determined using the data from the cash flow model, and therefore sensitive to the same assumptions outlined in (a) above.

Further details of the deferred tax assets recognised can be found in Note 5.

(g) Functional currency

An entity's functional currency is the currency of the primary economic environment in which the entity operates. If a foreign entity conducts significant amounts of business in more than one underlying currency, management's judgment will be required to determine the functional currency in which financial results are measured with the greatest degree of relevance and reliability.

With effect from 1 January 2013, the functional currency of two of the Group's Ukrainian subsidiaries has changed from US Dollars to Ukrainian Hryvnia. The change was triggered by the increasing influence of the Ukrainian Hryvnia on the subsidiaries' operations, compared to previous years. Whilst historically, the majority of the development costs were influenced by US Dollars and Euros, more recently these costs have been predominantly in Ukrainian Hryvnia. In addition, the internal gas price in Ukraine set by the National Electricity Regulatory Commission, and hence the Group's revenues, have been less influenced by the US Dollar than in previous years.

In line with the Group's internal reporting framework and management structure, the key strategic and operating decisions are made by the Board of Directors, who review internal monthly management reports, budget and forecast information as part of this. Accordingly the Board of Directors is deemed to be the Chief Operating Decision Maker within the Group.

The Group's only class of business activity is oil and gas exploration, development and production. The Group's operations are located in Ukraine, with its head office in the United Kingdom. These geographical regions are the basis on which the Group reports its segment information. The segment results as presented represent operating profit / (loss) before depreciation, amortisation and impairment loss.

There are no inter-segment sales within the Group and all products are sold in the geographical region in which they are produced. Gas sales to the Group's largest customer amounted to $25,980,000 (2012: two largest customers amounting to $10,833,000 and $4,711,000). Total revenue generated from operating and interest revenue is $37,598,000 (2012: $42,159,000).

*Comprises additions to intangible assets and property plant and equipment (Note 4)

**Discontinued operations all relate to operations in Romania, which were sold in 2012

4. Property, Plant and Equipment

In accordance with the Group's accounting policies, oil and gas development and producing assets are tested for an impairment loss at each balance sheet date. In assessing whether an impairment loss has occurred, the carrying amount of the asset is compared to its recoverable amount, which IAS36 defines as the higher of fair value less cost to sell and value in use. Management does not believe it possible to measure fair value reliably, due to both the absence of an active market in which to sell the asset and the current political and economic climate in Ukraine. Therefore, as in previous years, management has used value in use, using a discounted cash flow model, to measure its recoverable amount.

Due to mixed drilling results, the Group is undertaking geophysical studies, and has slowed down its field development programme on the Mekhediviska-Golotvshinska ("MEX-GOL") and Svyrydivske ("SV") gas and condensate fields in Ukraine. The revision to the field development programme has reduced the number and the phasing of new wells in the fields from 27 to 10. An updated reserves report as of 31 December 2013, prepared by ERC Equipoise Limited in London, based on this revised field development programme, revealed a revised estimate of the Group's 2P reserves of 11.7MMboe, compared to their previous estimate of 31.6MMboe at 31 December 2012. Further details of the updated reserves report are set out in the Operations Review section above.

This resulted in the recognition of an impairment loss of $159,199,000 (2012:$nil), to match the carrying value of the asset to its recoverable value, based on the revised estimate of value in use. The revised reserves estimate is the basis of the increased development and production asset depreciation charge for the year. It is impracticable to calculate the impact of the revised reserves estimate on the depreciation charge in future periods.

The calculation of value in use is most sensitive to the following assumptions:

(i) Commodity prices - The model assumes gas prices of $365/Mm3 (UAH3,020/Mm3), which was the gas price realised by the Group in the first quarter of 2014. A $10 decrease in the gas price would result in a further reduction of $3,735,000 in the carrying value of the asset, whilst a $10 increase in the gas price would result in an increase of $3,736,000.

(ii) Discount rate - The Group has estimated the discounted cash flows using a pre-tax discount rate of 17% (2012: 15%). This discount rate is derived from the management assessment of the relevant business risks associated with the MEX-GOL and SV fields. A 1% increase in the discount rate would result in a further reduction of $3,944,000 in the carrying value, whilst a 1% reduction in the discount rate would result in an increase of $4,285,000 in the carrying value.

(iii) Production levels - Production levels, are based on data included in the third party reserves report. This report includes estimated production volumes, including from new wells, over the remaining useful life of the MEX-GOL and SV gas and condensate fields in Ukraine. The report and its estimated production, is based on the Group's current development programme, which includes the drilling of 10 new wells.

(iv) The current licences, which are due to expire in July 2024, can be extended under applicable legislation in Ukraine until the end of the economic life of the field, which is assessed to be June 2036 on the basis of the updated reserves report. No application for such an extension has been made at the date hereof, but management consider the assumption to be reasonable based on their intention to seek such an extension in due course and that the Group is legally entitled to request an extension. However, if the extension were not granted, it would result in a further reduction of $9,339,000 in the carrying value.

5. Deferred Tax

At 31 December 2013, the Group recognised a deferred tax asset of $7,807,000 in relation to UK tax losses carried forward. There was a further $57 million (31 December 2012: $94 million) of unrecognised UK tax losses carried forward for which no deferred tax asset has been recognised. These losses can be carried forward indefinitely, subject to certain rules regarding capital transactions and changes in the trade of the Company. The Directors consider it appropriate to recognise deferred tax assets resulting from accumulated tax losses at 31 December 2013 to the extent that it is probable that there will be sufficient future taxable profits.

The deferred tax asset relating to the Group's development and producing asset at 31 December 2013 was recognised on the tax effect of the temporary differences between the carrying value of the Group's development and producing asset in Ukraine, and its tax base. This is deemed recoverable on the projected future profits generated by the Group's operations in Ukraine. The forecast profits are based on the current field development plan, and are determined using data from the same cash flow model, which was used to determine the carrying value of the Group's development and production asset in Ukraine, as outlined in Note 4. Based on these projections, the deferred tax asset recognised will be recovered by 2022. However, should future field development not result in additional production, only $3 million of the $29 million deferred tax recognised would be recoverable based on forecast profits available from the Group's existing wells.

The current tax charge for the year was $1,482,000 (2012: $1,660,000).

Factors affecting future tax charge

During 2013 the main rate of corporation tax in Ukraine was 19%. On 1 January 2014, the rate was reduced to 18%, with further planned reductions to 17% in 2015, and 16% during 2016 being the rate substantially enacted on the balance sheet date.

In March 2013, the UK government announced reductions in the main rate of UK corporation tax to 21% in 2014, and 20% in 2015. This is not expected to have a material effect on the Group's tax balances.

6. Reconciliation of Operating (Loss) / Profit to Operating Cash Flow

7. Post Balance Sheet Events

As announced on 25 March 2014, the Company engaged independent petroleum consultants, ERC Equipoise Limited, to prepare an updated assessment of the remaining Reserves and Contingent Resources attributable to the Group's MEX-GOL and SV fields. Further details are included in the Operations Review section above.

As a result of the recent political and economic upheaval in Ukraine, there has been a significant devaluation of the Ukrainian Hryvnia against the US Dollar which is likely to affect the carrying value of the Group's assets in the future. Since 1 January 2014, the Ukrainian Hryvnia has devalued against the US Dollar by approximately 25%.

From 1 January 2014, the Group's average realised gas price in Ukraine was $339/Mm3 (UAH3,051/Mm3). The Group's realised gas price is close to the maximum internal gas price set by the National Electricity Regulatory Commission of Ukraine ("NERC"). It has been announced by NERC that, with effect from 1 April 2014, the internal gas price will increase to $363/Mm3 (UAH4,020/Mm3 using the exchange rate at 31 March 2014 of UAH11.09/$1.00) for the second quarter of 2014. Further details are set out in the Finance Review section above.