Final Results

FOR IMMEDIATE RELEASE 31 MARCH 2011

JKX Oil & Gas plc

PRELIMINARY RESULTS

 FOR THE YEAR ENDED 31 DECEMBER 2010

Key Financials

·; Revenue flat at $192.9m (2009: $196.5m)

·; Production of 10,324 boepd, a decrease of 11% (2009: 11,665 boepd)

·; Capital expenditure rose by 66% to $178.5m (2009: $107.6m)

·; Non cash impairment provision of $74.6m against our operations in Russia reflecting revised assumptions on near term Russian gas prices

·; Operating profit before exceptional item of $95.0m (2009: $119.6m)

·; Basic earnings per share before exceptional item decreased by 12% to 47.56 cents (2009: 54.23 cents)

·; Cash at period end of $62.0m (2009: $74.4m)

·; Dividend for the year maintained at 5.0p per share

Operational Highlights

·; Steady progress in a challenging year

·; Completed and tested horizontal well R-103, Rudenkovskoye in Ukraine

·; Completed design and fabrication and commenced installation of LPG facility in Ukraine

·; Accelerated workover programme in Russia and additional well tested

·; Continued development and exploration in Hungary, Bulgaria and Slovakia

Outlook

·; Funded for development programmes

·; Gas production in Russia scheduled to commence in autumn 2011

·; Scheduled to enter fast-growing Ukrainian LPG market by mid-year

·; Remain on target to meet key production objective of 20,000 boepd during 2011

JKX Chief Executive, Dr Paul Davies, commented:

"While 2010 has been a challenging year, we believe that we are positioned to deliver a step-change in performance during the coming 12 months. Importantly, we are scheduled to commence production and revenue in Russia during the autumn of 2011, and we are also focused on increasing production in Ukraine, which remains the cornerstone of production. We remain confident in our long-term prospects and are committed to our strategy."

ENDS

For further information please contact:

A presentation to analysts will be held this morning at Brewin Dolphin (12 Smithfield Street, London, EC1A 9BD) at 9.30am.

Chairman's statement

In the short time I have been working with the senior team at JKX, I have been impressed by the management skills and operational potential in evidence. When I was approached to consider the role of Chairman of JKX following some 12 years on the Board at BP, I was attracted to the position because the company operates in a challenging area of the oil and gas sector, and one where I feel I can use my own experience and expertise to good effect. In addition to my time at BP, I have also served on the Boards of several other major companies, such as GlaxoSmithKline, and believe that this background can aid JKX in its plans for growth.

Having been in my position for only one month at the date of this release, it is too soon for me to comment on achievements with which I have had no involvement. Clearly, we benefit from a very strong production base in Ukraine, complemented by the development prospects in Russia and, albeit to a lesser extent, in Hungary.

Although considerable progress was made in 2010 on the large redevelopment project in Russia, the Company has experienced delays and capital cost increases; the commencement date for production in Russia is now expected in the autumn of 2011. More significantly, a delayed convergence of Russian domestic gas prices to European net-back levels is impacting our overall project economics and consequently we are making an impairment provision of $74.6m. 

Commitment to HSEC

My predecessor commented on the importance of protecting and nurturing our people, their communities and the environment, and this is a view which I share wholeheartedly. As a resource-based company, JKX rightly places great value on health, safety, environmental matters and community liaison (HSEC).

I note that the TRCF (Total Recordable Case Frequency) figures decreased in 2010 and are well below the industry benchmark. Furthermore, we were successful in our attempt to achieve ISO 14001 Environmental Accreditation during the year.

Your Board

My appointment has been the only change to the composition of the Board. I would like to place on record my thanks to Lord Fraser, whose sterling service of over 13 years saw JKX grow into an established operator in eastern and central Europe, and also become established in the FTSE 250 index. I know from conversations with senior management what a tremendous contribution Lord Fraser made, chairing the JKX Board with intelligence and great commitment. On behalf of the Board I thank him unreservedly.

Dividend

In a period of heavy investment, the Board recognises that increased taxation in Ukraine and delay in start-up of the Russian project inevitably impacts available cash flow. Consequently, the Board is recommending a final dividend of 2.6 pence per share, giving an unchanged total dividend for the year of 5.0 pence per share. The dividend will be paid on 24th June 2011 to shareholders on the Company's Register of Members on 6th May 2011. 

Outlook

The Company is budgeting a strong increase in production volumes for 2011 with higher oil realisations and continued increases in gas realisations in Ukraine. Despite these benefits, the Company is absorbing substantially increased production related taxes in Ukraine which it did not bear in 2010 and this will impact 2011 earnings.

Turning to our prospects for 2011, first gas in Russia in the autumn will be an important landmark for the Company. Ukraine will continue to provide the backbone of our cash flow and, together with Hungary, also provide us with exploration upside. In addition, we look forward to entering the fast-growing Ukrainian LPG market at mid-year and adding value to our existing gas business.

Finally, I wish to thank our people for their commitment and expertise over the last 12 months, as well as our shareholders for their continuing support.

Sir Ian Prosser

Chairman

Chief Executive's statement

We continue to focus on the proven strengths that form the backbone of JKX: an established presence in eastern and central Europe; extensive experience of local operating conditions; production and sales in buoyant local marketplaces; and locally-based and managed operating subsidiaries led by skilled and committed teams.

Our performance

2010 was a challenging year for JKX with drilling delays in Ukraine and construction delays on our Russian project. Notwithstanding these setbacks, the Company made significant progress on its key projects.

Average oil and gas production for the year decreased by 11% to 10,324 boepd (2009: 11,665 boepd) due primarily to the unscheduled delay in mobilisation of a second drilling rig to our development licences in Poltava, Ukraine. The effect of this production shortfall was essentially offset by the rise in both oil and gas realisations, leaving revenues broadly flat for the year at $192.9m (2009: $196.5m).  Operating profit (before deduction of an exceptional impairment provision) declined 20% to $95.0m (2009: $119.6m).

The exceptional impairment provision of $74.6m to the carrying value of our Russian project is largely the result of delayed net-back convergence of Russian domestic gas prices to those of European gas markets and its impact on overall project economics. We are now forecasting European net-back parity for 2017.

Milestones and progress

In last year's Annual Report, I laid out two key goals by which we would measure our performance. These were to:

·; Reach in excess of 20,000 barrels of oil equivalent per day production during 2011.

·; Increase production at Rudenkovskoye from 2% of JKX's Ukrainian production in 2009 to 25% in 2012.

We remain on target to achieve the first milestone but have moved the second milestone to 2013 to reflect the current schedule for the multi-frac operations planned for the Rudenkovskoye field.

 We remain confident in our long-term prospects and are committed to our strategy, including the four near-term objectives outlined in last year's Annual Report:

·; Accelerate the appraisal and development of non-producing fields and reserves in our existing portfolio, specifically at Rudenkovskoye in Ukraine and Koshekhablskoye in Russia.

·; Continue to optimise production from the producing fields in Ukraine.

·; Increase activity on our existing exploration and appraisal portfolio in central Europe.

·; Maintain flexibility to acquire additional interests in our focus area, to increase production and diversify geographically.

The fundamentals of our business and our markets are sound although we are experiencing some delay in turning upside into reality.

The installation and hook-up of the gas facility at Koshekhablskoye is now proceeding at pace. Despite on-schedule delivery of the key components of the plant from Sharjah to Russia in January, we are experiencing some slippage in the hook-up and commissioning schedule. Consequently, we are revising our target for first gas to this autumn. We continue to see excellent forward value in the Russian gas market and, once production is underway at Koshekhablskoye, we will turn our focus to extending our Russian operations to exploit opportunities elsewhere in what we regard as a region rich in potential.

In Ukraine, we drilled well R-103 on the deep Rudenkovskoye tight gas field as planned, and the encouraging initial results support our plans for the multi-frac stimulation of the well later in the year. Hook-up and commissioning of our LPG plant is underway at Poltava and we are currently scheduling initiating deliveries by mid-year. LPG continues to be an increasingly important energy source in Ukraine and 2010 again saw a sharp rise in the number of vehicles powered by LPG.

Our operations in Hungary, where we are non-operator, have progressed well with production increasing in Hadjunanas supported by the tie-in of the Gorbehaza-1 discovery. Gas has been tested in the Tizsavasvari-6 and Nyekpuszta-2 exploration wells and further appraisal is planned in 2011. The farm-in to the Turkeve licence has had mixed results with only one discovery to date.

Managing our risks

Risk is intrinsic to our industry and we expend considerable resources and expertise in managing it. During 2010, we ensured that robust risk management processes were in place, with oversight at Board level.

Outlook

We have the people, the strategy and the resources to deliver a step-change in performance during the coming 12 months.

We are confident we will commence production in Russia this autumn and I look forward to this operation becoming an important contributor to net cash inflow. We are working hard to increase production in Ukraine and this is a key component of reaching our key objective of producing 20,000 barrels of oil equivalent per day during this year. Start-up of our Ukrainian LPG facility by mid-year will also contribute an important value-added cash flow stream to our operations at Poltava.

Our people will once again be at the heart of our ambitions. In the countries where we operate we have teams of highly skilled individuals, most of them drawn from local communities and many of them trained by JKX. In the UK, we have an experienced senior team that has been complemented in recent weeks by the appointment of Sir Ian Prosser as Chairman. A former Deputy Chairman of BP, Sir Ian has in-depth knowledge and experience of international business, particularly in the oil and gas sector. At JKX, we are committed to grow as a Company and our ability to attract somebody of Sir Ian's calibre speaks volumes about our capability and intent.

I welcome Sir Ian to the Company and am looking forward to working alongside him during what I believe will be an exciting, productive and ultimately rewarding year. I must also express my appreciation to our outgoing chairman, Peter Fraser, who for the last 13 years has chaired this Company and supported me through every challenge we have faced.

Delivering our strategy

Operations Review - Ukraine

Poltava Petroleum Company ('PPC'), a wholly owned subsidiary of JKX, holds four production licences covering 127sq.km in the Poltava region of Ukraine. Each production licence contains a number of fields which together form the Novo-Nikolaevskoye Complex. PPC also holds the Zaplavskoye and Elizavetovskoye exploration licences comprising a total exploration area of 208sq.km.

The focus of the 2010 work programme was appraisal drilling in the Rudenkovskoye licence with the completion of the R-103 horizontal well in the fourth quarter. A second rig was contracted to maintain the development impetus in the second half of the period on the ongoing drilling programmes in the Ignatovskoye, Molchanovskoye and Novo-Nikolaevskoye fields. Delays in mobilisation resulted in completion of only one additional well by the second rig in the fourth quarter.

The programme of recompletions and stimulations continued throughout the period to maintain production levels in the Ignatovskoye and Molchanovskoye North.

In summary, PPC:

·; Drilled, tested and/or completed a total of 6 appraisal and development wells;

·; Carried out an acid frac and a propped acid frac on two carbonate wells;

·; Carried out 20 workover operations, including 12 recompletions, 3 well repairs, 3 fishing operations and 2 well abandonments;

·; Commenced installation of the LPG recovery plant;

·; Continued to upgrade and de-bottleneck the production facility; and

·; Installed additional generating and compression facilities.

The Ignatovskoye production licence is located in the centre of the Novo-Nikolaevskoye Complex and contains the first field to be developed by the Company. Evaluation of two additional structural trends continues, one to the west, and one to the southwest of the main field.

The main field is an uplifted fault block containing Devonian sandstone and overlying Carboniferous Tournasian sandstone and limestone. On top of that is a carbonate reef build up of Visean age. There is also a series of thin sandstone channels on the flank of the structure, also of Visean age.

Black oil is found in the Devonian sandstone and the lower parts of the Tournasian and Visean reservoirs; the oil is overlain by a rich condensate bearing gas cap and the Visean channels can be oil or gas bearing. Reservoir quality in the Devonian sandstone and Visean reef is generally good whilst both the Tournaisian sandstone and limestone are variable and often dependent on local depositional and tectonic influences. Reservoir stimulation in these reservoirs is usually necessary and, although this can give high initial flow rates, the rates often decline to a more modest plateau production.

There were no additional wells drilled or recompleted on the main structure of the field during the period and the focus of activity in 2010 was in recompleting and stimulating the wells in the west of the structure:

·; Development well I-137 was drilled as a Visean carbonate oil producer in the southeast of the field but was suspended in late 2008 with a fish in the hole below the 7-inch casing. A sidetrack was drilled in the period but encountered problems setting the casing. A re-designed replacement well is planned for 2011 in preference to further sidetracking.

·; Well I-105 was successfully worked-over with the recovery of broken downhole pump rods. A surface pump will replace the existing unit at a convenient time in 2011.

·; The workover rig successfully recompleted well I-133 from the Tournasian sandstone to a Visean sandstone oil producer. Reservoir pressure was insufficient to maintain flow and a beam pump has been installed with the well now supporting intermittent, but regular production.

·; Work began in well I-106 to carry out a water shut-off operation in the Devonian sandstone and recompletion as a Tournasian sandstone producer but problems recovering the tubing resulted in work being suspended until 2011.

·; Well I-110 was recompleted from the depleted Tournasian sandstone to the Tournasian carbonate.

A similar re-completion was performed on well I-158, but with only a small amount of gas being produced. The well is now a candidate for abandonment.

·; Wells I-131 and I-150 were abandoned in the period and their completion and well-head equipment recovered.

In addition to re-drilling well I-137, plans for 2011 include a well on the western flank of the main structure to appraise the potential in the down-dip fault blocks. Success on the flanks of the field would lead to a further re-appraisal of the field reserves which otherwise have remained relatively stable.

The Molchanovskoye production licence is located approximately 8 km to the south of the Ignatovskoye Field and contains the southernmost producing field within the complex. The licence now contains two distinct field areas:

Molchanovskoye North is a black oil reservoir with a gas cap in the Devonian sandstone and an overlying Tournasian sandstone gas condensate reservoir. There are also newly appraised overlying Tournasian carbonate and sandstone gas condensate reservoirs that extend over the Ignatovskoye licence boundary.

Work in 2010 addressed both the Devonian sandstone and the Tournasian carbonate reservoirs and also confirmed the presence of productive Visean sandstones within the licence area:

·; Development well M-167 was drilled as a high angle Tournasian carbonate infill well across the main natural fracture system in the Molchanovskoye North field. Drilling was suspended in 2009 due to a stuck drill pipe in the overlying swelling shale. The sidetrack was drilled successfully to a measured depth of 3,000m with a 400m section of Tournasian carbonate. Following a controlled acid squeeze on the low porosity formation, the well settled to a stabilised flow rate of 2.3 MMcfd of gas with 26 bpd of condensate through a 36/64" choke with a FWHP of 626 psi. Other areas of the extensive low porosity carbonate in the area are being evaluated for potential application of this development technique.

·; In mid-year, well M-166, a long horizontal well in the Devonian reservoir, showed a sharp increase in water production and a commensurate decline in oil and gas production. The TW-100 rig was mobilised to the location and gas lift installed to restore production. The re-drilling of a new horizontal section at a higher level is scheduled for 2011.

·; Devonian horizontal wells M-151 and M-152 watered out in the period and re-perforations higher in the well bores were unsuccessful. The wells are now candidates for abandonment.

·; Well M-169 was spudded in 2010 and was completed in March 2011 as a 600m long horizontal well in the Devonian reservoir. It is designed to replace both wells M-151 and M-152 and has been set higher in the reservoir. Initial test production was 5.25 MMcfd with 634 bopd oil at a FWHP of 594 psi through a 2" choke. Testing is ongoing at different choke sizes to assess the most effective production rate.

·; Well M-28, a long serving Devonian oil producer, was recompleted to the T2 sandstone and settled to a flow rate of 3.5 MMcfd with 90 bcpd.

·; The surprise of the year was the speculative perforation of the unlogged V16 sandstone reservoir in well M-161. This had initial flow rates in excess of 1,000 bopd with a high gas cut, but has been choked back to around 400 bopd for reservoir management purposes.

Activity planned for 2011 will include further in-fill drilling in the Devonian reservoir and further mapping of the Visean sands to seek analogies to the M-161 discovery. Reserves are not expected to change significantly.

Molchanovskoye Main produces gas condensate in the Devonian sandstone and is being evaluated for additional reserves in the overlying Tournasian carbonate and Visean sandstone reservoirs. Two wells were treated in 2010:

·; Development well M-206 was identified in 2009 as a suitable candidate for a propped acid frac of the Tournasian carbonate. The 2010 frac operation was successful but post-frac analysis indicates lack of reservoir connectivity.

 ..

·; Well M-205 was recompleted in the Visean sandstone where it flowed at an initial rate of 1.1 MMcfd of gas, despite more encouraging log results. Production enhancement by coiled tubing conveyed jet perforating was attempted but there was no noticeable improvement in flow rate.

The results of both treatments were disappointing and further work in this area has been assigned a low priority; this may affect the reserves recognised in this field area going forward.

A downthrown tilted fault block referred to as the "Wedge Zone" separates the Molchanovskoye North and Molchanovskoye Main fields. An exploration well M-170 is currently drilling ahead towards its planned TD of 3,100m in the Devonian sandstone to evaluate the potential of this 1 sq km block. A second well in the block is tentatively planned for later in 2011. No reserves are currently attributed to this area of the field complex.

The Novo-Nikolaevskoye production licence lies 3km to the west of the Ignatovskoye Field. Following successful drilling in 2009, remapping and additional drilling was carried out in 2010 with plans for more wells in 2011.

·; Development well N-73 was drilled as a Visean sandstone gas producer and flowed at a stabilised rate of 1.97 MMcfd of gas, 27 bcpd and 110 bwpd with a FWHP of 189 psi. A well intervention was subsequently carried out to isolate the water producing zone.

·; Well N-74 was spudded in the fourth quarter and encountered gas in two Visean sandstone horizons; it is currently flowing at 3.5 MMcfd with 114 bcpd.

The success of wells N-73, N-74 and M-161 will contribute to an increase in reserves in both the Novo-Nikolaevskoye and the Molchanovskoye licences when they are reassessed later in 2011. Three further wells are planned for 2011 with the first well (N75) scheduled to spud in the third quarter.

The Rudenkovskoye production licence is the most northern of the four production licences. Reservoirs in the licence are the Tournaisian and Devonian sandstones at depths of between 3,000m and 5,000m with further potential in the overlying Visean sandstones. Productive areas have been identified in the northern and southern areas of the licence and, after the modest success of the 2009 propped frac programme, an initial three well horizontal drilling programme was planned for 2010-2012:

·; Well R103, in the southern part of the field, was drilled to a measured depth TD of 4,641m using the Skytop N-75 rig with 1,026m of the well drilled horizontally in the Devonian reservoir. On test, the well flowed at a stabilised rate of 8.1 MMcfd of gas and 18 bpd of condensate through a 85/64" choke with a flowing wellhead pressure of 930 psi over the final 8 hour period of a multi-rate test. The well was been tied back to the main field processing facility with an 8km flow line and placed on production. Since then, production has declined, compounded by an inability to lift the remaining drilling and completion fluids, despite changing the tubing to a smaller size. Rates are currently around 650 Mcfd with 1-2 bcpd and intermittent water. Geological and engineering studies are underway for a multi-stage frac in the long horizontal wellbore.

·; Well R102, was drilled in early 2007 in the southern area of the field. It found two main gas-bearing zones in the Devonian sandstone but the presence of water precluded any fracture stimulation testing in the lower interval and the well was plugged back to a higher, and much thinner, interval in the Devonian. The propped frac operation was relatively successful and the well flow rate increased 4 times to 0.5 MMcfd of gas. In 2010, the perforated zone was extended and this resulted in an increase in production to 1.6 MMcfd.

·; The sites for the R-104 well in the north of the Rudenkovskoye area has been prepared and the programme for this 4,300m horizontal well to the Visean sandstone reservoir is ready, as is the programme for well R-105, a further well in the area of well R-103. Both wells R-104 and R-105 have been deferred until the results and prospects for well R-103 have been fully evaluated.

Reserves reassessment in the Rudenkovskoye field areas will await the results of the R-103 multi-frac and the subsequent drilling programme.

Poltava Production facilities: 2010 saw continued improvements to the Central Production Facility with:

·; Commissioning of the replacement compressor K220 early in the year to provide greater support for gas-lift and production optimisation - an increasingly important aspect of field management;

·; Commencement of a review into the efficiency of the surface facilities to identify potential operating improvements.

·; Implementation of the recommendations of an independent specialist team to debottleneck the plant and enhance the process facilities. Initial steps included replacement or duplication of some flowlines to reduce back pressure on the wells. Notably, the results for well I-125 were significant with gas production increasing from 1.9 MMcfd to 2.4 MMcfd and oil production from 31 bopd to 220 bopd. Further work will be undertaken during the annual field shut-down.

Improvements to the sewage treatment facility at the production site are planned for 2011 and there will be minor improvements to the roads and walkways throughout the facility.

LPG Plant: Fabrication and construction of the LPG plant commenced in the period. All the LPG process equipment is now onsite and installation has commenced. Installation and construction of the storage and loading equipment is also in progress. Completion is now expected in June 2011.

The Zaplavskoye exploration licence is adjacent to the Molchanovskoye production licence and comprises an area of 137.6 sq km. The permit has been extended for a further 5 years until 2014. In addition, the area has been extended by 41.9 sq km and in-fills an area between the Novo-Nikolaevskoye and Ignatovskoye licences where existing seismic indicates potential drilling targets and extends the western flank of the Ignatovskoye field. The extension also includes the Shagarivske area to the east of the Ignatovskoye field where a 100 km 2-D seismic programme was shot in late 2010 ahead of exploration drilling planned for 2012. The first well in the new block is likely to be in the area to the northwest of the Novo-Nikolaevskoye field and will target Visean sandstone reservoirs already encountered in drilling undertaken by the State in the 1980s.

The Elizavetovskoye exploration licence is located in the central part of the Dnieper-Donets basin and covers an area of 70 sq km. It is approximately 45km from PPC's existing production licences. Three shut-in production wells on the licence are owned by Ukrgasvydobuvannya, a subsidiary of Naftogaz of Ukraine, the state oil and gas company, and are tied into its production facility.

·; Negotiations with Ukrgasvydobuvannya were concluded in 2010 and enabled PPC to start preparations for drilling its own production wells in the field.

·; Plans have been prepared for the drilling of a single well and the installation of basic separator and dehydration equipment tied to the local branch gas line via a hot tap. The project is currently scheduled to commence in early 2012.

·; The hot tap installation is scheduled to be carried out by Ukrainian specialists in the second quarter of 2011 as an essential pre-requisite of the rest of the programme.

The Chervonoyarske East exploration licence was acquired in December 2005. The licence covers a total area of 5.5sq km and is located about 75km from the PPC production licences on the northern margin of the Dnieper-Donets basin. Evaluation of the 42 sq km 3D seismic survey acquired in 2008 supports the interpretation of potential hydrocarbons trapped against the flanks of a major salt wall. However, the cost of drilling to below the salt and the geological risks associated with the traps are high. Attempts to farm-out the licence during 2010 were unsuccessful and the licence was relinquished in December 2010.

Ukrainian Reserves: As described above, the ongoing work in the Poltava fields has meant that no reserves reassessments took place in 2010. Drilling, workover and seismic activity will continue in 2011 and it is envisaged that a reassessment of the Ignatovskoye, Molchanovskoye and Novo-Nikolaevskoye fields will be completed towards the end of the year, although it will be 2012 before this can be concluded in the Rudenkovskoye field areas.

Operations Review - Russia

Koshekhablskoye Field Redevelopment: JKX completed the purchase of Yuzhgazenergie LLC ('YGE') in November 2007. YGE holds the licence for the redevelopment of the Koshekhablskoye gas field which is located in the southern Russian autonomous Republic of Adygea. The licence covers an area of 32.7 sq km.

The field was discovered in 1972 and produced a total 89 Bcf of gas before operations were suspended in January 2006. In June 2006, YGE was granted a new 20 year licence to rehabilitate and further appraise and develop the field.

Following the acquisition, the detailed technical and environmental re-evaluation by JKX concluded that the existing production facility would have to be completely replaced because it could meet neither the new gas specification required for entry to the Gazprom transit system nor the environmental standard for emissions to the immediate environment.

The focus during 2010 was on continuing the workover of wells to ensure that the Gas Processing Facility (GPF) would be brought on-stream at full capacity and completing the construction of the processing plant to ensure that construction and commissioning of the complete facility could be completed for first gas in the Autumn 2011, delayed from mid-year.

During the period, YGE has:

·; Completed the workover, sidetracking and successful testing of Well-20 at a final flow rate of 22.6 MMcfd of gas and 25 bcpd through a 60/64" choke with a flowing wellhead pressure of 1,510 psi.

·; Re-entered Well-25 on the north flank of the field using the Geostream KES-536 rig, and recovered the remainder of the tubing. Drilling of the 260m sidetrack into the limestone reservoir kicked-off at 5,490m with a targeted TD of 5,760m. Completion and testing is scheduled for the beginning of the second quarter.

·; Initiated milling and fishing operations on Well-26 and suspended operations after recovering 314m of fish with 1,375m remaining. It is planned to return with a smaller rig to complete fishing more economically.

·; Completed fishing on Well-15, deep on the east flank of the field, and drilled a sidetrack to a depth of 5,755m with strong gas shows and encouraging logs. Disappointingly, the sidetracked well bore did not stay open during testing with an obstruction preventing deployment of the coiled tubing to TD in the open hole section. Due to the priority given to the other wells in the first phase programme, remedial action (which may include a new sidetrack to a more geologically prospective part of the field) will be undertaken as part of the second phase of well recompletions later in 2012.

·; Recovered tubing from the Callovian appraisal Well-09 to a depth of 5,312m using the Kremco-900 rig. Preparations are currently underway to sidetrack the well through the Callovian sandstone reservoirs to a TD of 5,500m. Completion and testing of Well 09 is now scheduled for the fourth quarter of the year.

·; Commenced fishing operations on Callovian exploration Well-22 using a lightweight A-125 rig. The well has been suspended at 4,885m awaiting mobilisation of the Geostream KES-536 rig to deepen the well to 5,570m in the Callovian sandstone reservoirs. Completion and testing of Well 22 is scheduled for the fourth quarter of the year.

·; Completed the laying of replacement flowlines for the whole field, installation of the export line and the tie-in to the local trunk line.

·; Completed the construction and hook up of additional temporary field camps to house construction workers and drilling teams.

·; Fabrication of key components of the GPF plant in Sharjah was completed during the last quarter of 2010 with the final shipment leaving port at the end of December, slightly ahead of schedule. All equipment has now been off-loaded and cleared through customs in the Russian port of Novorossiysk, some 300km from the field and transported to the site. Foundations for the equipment are in place and the construction teams have begun installation.

·; Installation and construction of locally sourced equipment and buildings is nearing completion with hook-up and commissioning of the plant scheduled to commence by the end of the first quarter.

·; First commercial gas production is scheduled for the beginning of the third quarter.

The workover programme has encountered difficult conditions in some of the wells, and the programme has been revised to ensure that production will meet the targets for the GPF as commissioning begins in the second quarter. The goal is to have three wells in production at start-up with further wells being brought on-stream in the second phase of workovers in 2012.

Koshekhablskoye Field Exploration and Appraisal: JKX inherited a YGE obligation to drill an exploration well to appraise the production potential of the underlying Callovian sandstone reservoir. YGE has subsequently undertaken a significant amount of exploration and appraisal activity on the Callovian reservoir including:

·; acquisition, processing and interpretation of the 3D seismic;

·; integration of the maps with a complete re-evaluation of the well logs and other geological data to determine reservoir distribution and the potential resources in the Callovian sandstone; and

·; acquisition of the shut-in Callovian production Well 09 for early testing.

In recognition of YGE's commitment to the exploration programme and the high cost of deep drilling, the Russian State Geological Institute responsible for the YGE ongoing exploration and appraisal programme accepted the Company's proposal to deepen an existing dry Oxfordian appraisal well (Well-22) to the Callovian reservoir in order to reduce significantly the overall cost of the project. The testing of the Callovian V unit in Well-09 and the deepening and evaluation of Callovian zones I-V in Well-22 will be concluded later in 2011.

Russian Reserves:

Following the results of the Well-27 test, the production characteristics of the field were revised and the material balance reserves forecast reassessed. This resulted in a revision of the P+P reserves to 44.8 MMboe during 2009. The Oxfordian reserves will be reassessed (as a licence obligation) later this year once the results of the Well-25 testing can be incorporated. Callovian reserves are dependent on the results from Well-09 and Well-22, and will be revised in 2012.

In addition, YGE has received a letter of assurance from the Russian authorities confirming that any field reserves lying outside the licence boundary could be included in a revised licence area (provided this did not exceed 125% of the existing licence). This permits YGE to increase the field reserves by up to a further 40% when the licence has been formally extended and is scheduled to occur after first gas production.

Operations Review - Hungary

Hernad Licences:  JKX holds 50% equity in the northern Pannonian Basin Hernád licences in a joint venture with the operator, Hungarian Horizon Energy ('HHE'). The Hernad I licence covers 2,903 sq km and the Hernad II licence covers 2,507 sq km. The Pannonian Basin comprises numerous sub-basins developed across Hungary, Slovenia and Romania. It is prospective for gas and oil, and exploration risk can be reduced by the use of seismic data attributes (amplitude versus offset or AVO) and calibrated well log data. The post-rift sequence contains channelised and lobe turbidite sand reservoirs in combined structural/stratigraphic traps. Miocene age pro-delta shales provide the source for the gas and condensates.

Hajdunanas Field: The Hajdunanas Field was discovered in May 2008 with successful gas tests from three levels in well Hn-1. The discovery was confirmed by a second well Hn-2 which encountered a thicker sequence of Pannonian sands. The reservoirs include two Pannonian sand intervals and a Miocene fractured volcanoclastic sequence. Gas quality is excellent and requires minimal processing before export. The Gorbehaza discovery well Gh-1 in the Nyírseg licence has been tied in the Hadjunanas facility.

·; Following the successful workover of the Hn-2 well and recompletion of the Gh-1 well in the fourth quarter of 2010, current gross production is approximately 7 MMcfd of gas and 180 bcpd. 

·; The field operator, Hungarian Horizon Energy (HHE), and JKX are planning a 20% increase in production in the second quarter of the year. 

·; The local gas market remains strong with 2011 realisations to date in excess of $10 /Mcf.

Hajdunanas Reserves: No changes have been made to the Hadjunanas reserves in 2010. The effects of the minor water influx - now successfully shut-off - are being evaluated.

Further Hernad Exploration Activity:

·; The Tiszavasvari-6 well was drilled in the second quarter of 2010 and tested during January 2011. The well encountered a 300m gross reservoir interval with excellent gas shows in the deeper secondary target below 2,580m. Three reservoir intervals were tested with a maximum rate of 1.5 MMcfd being recorded. The well has been suspended in anticipation of a possible reservoir stimulation programme.

·; A larger tilted fault block structure with amplitude supported Lower Pannonian reservoir intervals lies updip from the first structure and is estimated to contain an initial gas in place of between 50 and 150 BCF. Appraisal drilling is scheduled for the second quarter of 2011.

·; Additional amplitude supported exploration targets in Upper Pannonian shallow water sands have been identified to the north-east of the Hajdunanas Gas Facility. Permitting is underway for a test of a three way dip and fault closed structure with a TD of approximately 800m. Numerous low risk but small additional prospects would be de-risked by a successful well.

·; The Tiszatarjan-1 exploration well, approximately 12 km from the Hadjunanas field, remains suspended as an oil discovery, pending a forward programme of formation stimulation.

·; A further 300 sq km 3D seismic data acquisition is planned for the Jaszsag area in the south of the Hernad II licence during the first half of 2011.

Nyirseg Licence: JKX farmed-in for a 33.3% interest in 120 sq km of the adjacent Nyírseg licence operated by PetroHungaria in late 2008.

·; JKX subsequently increased its holding to 50%, as did HHE, by buying out the minority partners.

·; The first well Görbeháza-1 tested 3.74 MMcfd of gas and 20 bcpd and has been tied into the Hajdunanas gas production facility some 2.5 km away.

·; First gas was achieved in August 2010.

·; The offset Gorbehaza-5 well, drilled in early 2010, was water bearing and has been completed as a potential water disposal well for the Hajdunanas facility.

Veszto Licence: In March 2009, JKX farmed-in for a 25% interest in a 15.6 sq km area of the Veszto exploration licence held by HHE in the eastern Pannonian Basin. A 3D seismic survey covering the entire 219 sq.km licence has been completed and interpreted with two prospects identified.

Following abandonment of the Nyekpuszta-1 well because of unexpected high pressures (12,000psi) and temperatures (175ºC), the Nyekpuszta-2 appraisal well was successfully drilled to 3,695m in late 2009. The well encountered a gross hydrocarbon column of 85m and was fracture stimulated and tested in 2010. Despite flow rates being constrained by the abrasion due to returning proppant, the rates were initially steady at 2.0 MMcfd and 600 bpd oil/condensate with a FWHP of 4,500 psi. However, this rate was not sustained through the two month test period. After a one month final shut-in, reservoir pressure built back to original levels. The slow build up indicates a low permeability connection of the main reservoir volume to the fracced interval. It has been concluded that this potentially very large (>200Bcf) structure will require additional appraisal drilling and formation stimulation.

JKX and HHE continue the evaluation of the prospect specific and regional structural model in the light of the extended test results from the Nyekpuszta -2 well. A further well is planned for the third quarter of 2011.

In addition to the testing and completion of the Nyekpuszta-2 well, activity under consideration for 2011 includes evaluation of a similar prospect within the Veszto Licence in which JKX has an option to participate.

Turkeve Acreage (JKX 50%): JKX has entered into an agreement with HHE to farm-in to the drilling of up to seven wells located in the Turkeve area of north east Hungary. Under the terms of the agreement, JKX funds 66.67% of drilling and completion costs to earn 50% of future mining plots formed to develop discoveries, and also funds 75% of pipeline connection costs. There has been one encouraging result out of the five wells drilled to date and a tie-back to existing facilities is planned for the second quarter. The remaining two wells will also be drilled in the second quarter.

Rest of World

Operations Review - Bulgaria

JKX (40% and operator) operates two onshore exploration permits, B Golitza and B1 Golitza, covering a total of 3,355 sq km in eastern Bulgaria. The licences include the area of the Kamchia Trough, an onshore extension of the Tertiary age western Black Sea Basin, now the subject of renewed deepwater exploration activity.

The 2009 seismic data acquisition of 250 sq km 3D was completed in the Kamchia Trough, south of the town of Varna. The initial interpretation revealed several prospects and a two well drilling campaign began in the 3rd quarter of 2010.

·; The Staro Oryahovo South R-01 exploration well, was drilled to a total depth of 1,875m. Gas shows were encountered during drilling of the target Avren Formation submarine fan sandstones, but subsequent log analysis demonstrated that the target was water wet. The well was plugged and abandoned.

·; The Shkorpilovtci South West R-01 exploration well was drilled to a total depth of 837m and was plugged and abandoned. Significant gas shows were observed during drilling of both the primary target Avren Formation channel sand complex and the underlying secondary target Dvoynitca Formation sandstones. However, wireline data in the Avren Formation indicated poor reservoir permeability, and consequently a well test was not performed. The well appeared to have encountered a channel margin in this location and the shallow depth to the primary target precluded a geological sidetrack. The highly laminated underlying secondary reservoir was determined to be water wet.

The lack of success of both recent Golitza wells was disappointing, but JKX and its co-venturers believe they can integrate the information from these wells with the 3D seismic to high-grade further exploration targets within the Avren Formation.

Operations Review - Slovakia

In 2008, the Company farmed-in for a 25% interest in the Svidnik, Medzilaborce and Snina exploration licences, covering a total area of 2,278 sq km in the Carpathian Fold Belt in north east Slovakia. Acquisition of 346 km of 2D seismic data in 2008/2009 provided basic regional information in the two eastern licences, as well as infill data in the western Svidnik licence.

In 2010, a further 150km of 2D seismic data were acquired to firm up leads identified in the 2008/2009 surveys. A structure has been confirmed in the vicinity of the Smilno discovery well in the Svidnik licence, and plans are being made for drilling an exploration well, possibly in the latter part of 2011. Further regional seismic data acquisition is planned for the third quarter of 2011.

Financial review

2010 was a year of significant capital expenditure underpinned by continued solid operating cash flow, most importantly from our Ukrainian subsidiary Poltava Petroleum Company ("PPC"). Whilst production decreased as a consequence of delay in mobilising a second rig to Ukraine, increased international commodity prices, combined with effective operational cost control resulted in the second highest operating cash flow generation in the Group's history.

Profit for the year

The profit after tax for 2010 was $21.2m (2009: $85.3m) although, excluding the impact of the non-cash exceptional item of $74.6m and the resulting deferred tax credit of $14.5m, the profit after tax is $81.3m. The impact of the exceptional item is further discussed below. The basic earnings per share was 12.38 cents per share (2009: 54.23 cents per share) or, excluding the impact of the impairment provision, was 47.56 cents per share. 

Revenue

Total revenues of $192.9m were down 2% (2009: $196.5m), a direct result of an 11% decrease in production offset by a 28% increase in oil price and 6% increase in gas price. The average oil price achieved was $69.15/bbl (2009: $53.90/bbl) with a gas price achieved of $7.59/Mcf (2009: $7.19/Mcf).

Operating profit

The combined cost of sales and general, administrative costs and loss on foreign exchange, before impairment, exceptional item and profit on sale of assets, were 13% higher at $84.2m (2009: $74.4m) comprising:

·; Depreciation, depletion and amortisation which increased slightly to $33.2m (2009: $32.8m) despite the 11% drop in production, a function of the greater production contribution in 2010 from proportionally higher capital expenditure fields in Hungary and Rudenkovskoye in Ukraine;

·; Production related taxes, which increased 30% in the period to $5.2m (2009: $4.0m), mainly because of a greater contribution from Hungary which accounted for 7% of production and 45% of production related taxes;

·; Underlying operating costs (cost of sales less DD&A, impairment, exceptional item and production based taxes) declined 13% on last year to $17.9 m (2009: $20.6m), due to savings and ongoing efficiencies being achieved in operations. However, underlying operating costs combined with general and administrative expenses increased 22% during the period from $35.3m to $43.2m. This represents significant one off corporate costs in Ukraine along with increased expenditure associated with "staffing up" the Russian subsidiary Yuzhgazenergie, and a number of one off expenditures in our period of transition from project development towards an operating company. The net loss on foreign exchange of $2.6m was up16% (2009: $2.3m).

Provisions for impairment of fixed assets and write-off of exploration costs of $13.7m (2009: $5.0m) recognises the write off of Ukrainian exploration well Zaplavskoye 3 ($6.2m) and licence costs for the recently relinquished Chervonoyarske licence ($1.0m). Additionally, the Group wrote off during the period its share of two exploration wells in Bulgaria ($1.7m) and one in Hungary ($1.9m). A provision was also made for an asset which was previously held for Russia of $2.9m.

The exceptional item relates to an impairment provision taken on our Russia asset, the details of this are documented within note 5 (e) and 5 (f) of the financial information.

Impairment

A review was undertaken at the balance sheet date to determine whether there was any indication of triggers that may have led to any assets requiring an impairment review. Following this review, an impairment trigger was noted in relation to Yuzgazenergie (YGE) in Russia and Poltava Petroleum Company (PPC) in Ukraine. Having undertaken the review, it was concluded that PPC'S Novo-Nikolaevskoye complex was not impaired.

An impairment review was undertaken for YGE.

The development plan and production profile have continued to be refined since the 2007 acquisition of YGE. First gas sales from the project are now expected Autumn 2011, three years later than planned and anticipated convergence of Adygean gas prices to net back European levels is now delayed to 2017. The current level of gas prices in Russia are also lower than those anticipated in March 2010. 

The key assumptions used in the impairment testing were:

·; Production profiles based on latest information provided by independent reserve engineers, such information including 2P reserves (44.8 MMboe) and 3P and contingent resources;

·; Economic life of field (expected to be around 2032);

·; Gas prices based on the Russian Government's intention to achieve net-back convergence with the European gas markets which the Group has assumed as occurring in 2017 (2009: 2015);

·; Capital and operating costs: based on project estimates;

·; Post tax Rouble discount rate of 13.5% (2009: 15.9%).

The changes in the key assumptions used from previous periods has resulted in the asset being impaired by $74.6m. No value was attributed to 3P and contingent resources. The main driver of the impairment has been lower sales prices anticipated in the early years together with a longer period before net back European gas price parity is achieved. The Group has recognised the impairment charge as an exceptional provision within the accounts.

Taxation

The effective tax rate for the Group in 2010 was (1.8%) (2009: 28.5%). The significant reduction results from three main factors: deferred tax effect of $14.5m in relation to the $74.6m Russian asset exceptional item; the recognition of a deferred tax asset in the UK; and reduced current tax on core Ukrainian operations resulting from reduced taxable income.

Dividend

The Board proposes a final dividend of 2.6 pence per share (2009: 2.7 pence per share) giving a full year dividend of 5.0 pence per share (2009: 4.9 pence per share). The proposed dividend will be recognised when paid.

The Board has decided that not increasing the full year dividend is appropriate, following continued extensive capital being invested in the Group's YGE redevelopment project in southern Russia, coupled with the cash impact of rental payments in Ukraine following the 1st January 2011 introduction of Ukraine's new tax code.

Cash flow/Net cash

Net cash from operating activities (after tax payments of $28.5m) was $117.7m, which is 7% lower than the previous year (2009: $126.5m). This reflects the lower PPC production in the period partially offset by higher commodity prices. There was an 81% increase in total net cash used in investing activities to $175.1m (2009: $96.7m). This was due to the increased capital expenditures to $172.8m (2009: $108.7m) mainly on the continued development of PPC's licences in Ukraine, the YGE redevelopment of the Koshekhablskoye field in south west Russia, and the Group's growing Hungarian asset portfolio.

The Group raised funds in February 2010 via a share placing which, together with share options exercised, resulted in a $58.4m cash inflow from financing. The dividends paid in the year were $13.2m (2009: $12.3m).

The Group is confident in being sufficiently funded to meet the capital commitments of its current development programmes. This confidence comes from the Group's current cash position and positive operating cash flows.

Financial Review