JKX Oil & Gas plc Report & Accounts 2010

Transcription

1 JKX Oil & Gas plc Report & Accounts 2010

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3 JKX Oil & Gas plc Annual Report & Accounts At a glance An overview of our business In detail Our business in greater depth CONTENTS 02 What we do 03 Highlights 04 Our regions 06 Our marketplace 08 Our strategy and progress 10 Our resources 12 Our performance CONTENTS 14 Chairman s statement 16 Chief Executive s statement 19 Delivering our strategy 20 Operational review 20 Ukraine 26 Russia 30 Hungary 33 Rest of world 34 Financial review 38 Risks we face and how we manage them 42 Corporate Social Responsibility review 44 CSR case study Russia 46 Health and safety 48 Environment 49 Employment 49 Community 50 Directors reports 50 The Directors 52 Directors report 55 Corporate governance 60 Remuneration 69 Financial statements 72 Group accounts 110 Company accounts 118 Notice of Annual General Meeting

4 02 At a glance What we do / Highlights What we do We draw on our extensive, long-established regional experience and expertise to develop oil and gas interests in eastern and central Europe, with a particular focus on Ukraine and Russia.

5 JKX Oil & Gas plc Annual Report & Accounts Highlights Rudenkovskoye development We completed and tested horizontal well R-103 at Rudenkovskoye in Ukraine, which produced encouraging initial results Revenue ($m) -2% Workover acceleration We accelerated the workover programme in Russia and tested an additional well. LPG facility We completed the design and fabrication stages and commenced the installation of the LPG facility in Ukraine Operating profit after exceptional item: $20.4m Operating profit before exceptional item ($m) -21% Development and exploration We continued our development and exploration in Hungary, Bulgaria and Slovakia Capital expenditure ($m) +66% Net cash ($m) -17%

6 04 At a glance Our regions We have operational experience and expertise in the eastern and central regions of Europe km2 Svidnik Medzilaborce 720km2 Snina 996km2 S L O V A K I A H U N G A R Y Hernad 5,410km2 Nyirseg 120km2 Turkeve 1,018km2* Veszto 15km2 1,787km2 Golitza 1,241km2 Provadia B U L G A R I A * Final Turkeve area subject to drilling results Reserves proved and probable MMboe/depth as at 31st December 2010 Ukraine Ignatovskoye Molchanovskoye North & Main NovoNikolaevskoye Rudenkovskoye Russia Hungary Koshekhablskoye Hernad and Nyirseg Note: Pantone 376c Illustrator File profile is - US WE RGB (ADOBE RGB profile) Gree R G B ,000m 2,000m 3,000m 4,000m 5,000m 6,000m Oil Gas

7 JKX Oil & Gas plc Annual Report & Accounts with a particular focus on Ukraine and Russia Elizavetovskoye Novo-Nikolaevskoye Complex 71km2 265km2 U K R A I N E R U S S I A Koshekhablskoye T H E B L A C K 32km2 S E A G E O R G I A Group reserves as at 31st December st Jan 2010 Revisions TOTAL Oil + Gas MMboe Oil MMbbl Gas Bcf Gas MMboe (3.7) (1.1) (15.7) (2.6) Gas Bcf Gas MMboe (1.1) (14.4) (2.3) RUSSIA Oil MMbbl Gas Bcf Gas MMboe HUNGARY Oil MMbbl Gas Bcf Gas MMboe (1.3) (0.3) EB COATED (SWOP2) UKRAINE en should be Oil MMbbl Production 31st Dec 2010

8 06 At a glance Our marketplace a marketplace that is rich in opportunity for us, across both the oil and gas sectors. Marketplace As an upstream company, the oil and gas we produce is sold at or near the edge of our facilities, at which point responsibility passes to our customers. Oil Proved world reserves (Billion barrels) Hungary: Ukraine: Russia: World: 1, Gas Proved world reserves (Trillion cubic feet) Russia 1, Ukraine: World: 6,261.00

9 JKX Oil & Gas plc Annual Report & Accounts Each of the regional markets in which we operate is a net consumer of oil and gas, (whilst overall as a country Russia is a net producer, the south west Russian regional market within which we operate is a net consumer). We believe that the opportunities open to us in these markets are likely to expand, as governments and relevant authorities recognise that investment by non-state companies is an attractive route towards increasing production regionally. We are well-positioned to exploit these opportunities. Production ( 000 bpd) Consumption ( 000 bpd) ,000 7,500 9, , ,500 2, Ukraine Russia Hungary 0 Production (Bcf per annum) Consumption (Bcf per annum) 2,000 20,000 20, ,500 1,560 15,000 15, , , , Ukraine Russia Hungary 0 Source: USA Energy Information Administration

10 08 At a glance Our strategy and progress This is the strategy via which we aim to seize that opportunity Objective Strategic priorities Achievements To build on our well-established strength as an efficient and successful developer and producer of oil and gas interests in eastern and central Europe. Growth Increase production. Explore new opportunities across our existing portfolio. Acquire new licences. Continue to enhance and exploit our local expertise and know-how. Increase oil and gas reserves. Maximise exposure to, and deliver value from, the Ukrainian and Russian gas markets. HSEC & Sustainability Continually strive to improve on our strong record on: HSE performance. Environmental performance. Supporting our people. Supporting local communities. Drilled and tested horizontal Well R103 on Rudenkovskoye field in Ukraine as next phase of development programme. Accelerated the redevelopment of the Koshekhablskoye field in Russia. Further exploration drilling in Hungary. Enhancement of dedicated specialist teams in each country, including geological, geophysical, materials and drilling resource. Enhancement of London-based Group technical team. Maintenance of efficient cost base. Rigorous monitoring of All Injury Frequency Rate. Good progress made in reduction of emissions towards 12.5% target from 2008 to Introduction of new system for employee dialogue. Deliver long-term shareholder value Regularly assess and ensure adherence to comprehensive and clear policies, procedures and controls to budget forecast and control all group expenditures. Maintain payment of a dividend in line with performance and capital requirements. Add reserves and enhance production profile. Clear commitment to the Combined Code. Dividend of 5.0p announced for Expenditure controls maintained during a period of heightened capital investment.

11 JKX Oil & Gas plc Annual Report & Accounts the progress we are making and the performance measures we use. Performance measures Production volumes (boepd) 10 10, , ,012 The Board considers the future production profile of the Group s interests to underpin the value of its asset portfolio. Accordingly, the level of annual production is the measure by which management monitors delivery of portfolio development. The 11% fall in average combined oil and gas production is the result of the unscheduled delay in mobilisation of a second drilling rig to our PPC producing fields. Capital expenditure ($m) Capital expenditure is used by management to monitor levels of investment, on both a country specific and regional basis. Capital expenditure increased significantly on 2009 (up 66%) as the redevelopment of the Koshekhablskoye field in Russia accelerated in the period. Production costs ($ per boe) The Board believes a core skill of the Group to be the low cost development of onshore gas assets in and around Ukraine. A key measure used to monitor this is the level of production costs which remained materially consistent with Ukrainian gas realisations ($ per Mcf) The Board has pursued a strategy to maximise exposure to and deliver value from the Ukrainian and Russian gas markets. This is based on the belief that as occurred in Ukraine, the Russian domestic gas price will, after accounting for net-backed transportation costs, converge with gas prices in western Europe. In 2010 the 2% increase in Ukrainian gas realisations is evidence of the convergence that has occurred and from which the Group is benefitting. With the Group s first Russian gas production expected in Autumn 2011, Russian gas realisations will be the realisations KPI going forward. All Injury Frequency Rate We are committed to continuously improving our health and safety performance. During 2010 we again maintained our progress, with a significant 59% decrease in our AIFR (All Injury Frequency Rate) figures. The AIFR represents the health and safety incidents per 200,000 man-hours. To put our achievement in to context, the industry benchmark for 2010 was 3.4. Return on average capital employed (%) Exceptional item: 12.1% The Board believes its strategic objective of returning value to shareholders is most appropriately measured by the return on average capital employed. It believes that this measure reflects the underlying ability to return value by a combination of dividends, share buy-backs and any capital appreciation in the Company s equities as may be determined by the capital markets. The 26% decrease (excluding exceptional impairment) in 2010 reflects the continued significant investment programmes, particularly in Russia and the decreased net profit achieved in the period. Reserves at the end of the period (MMboe) The Board believes that a significant component of the Group s ability to add shareholder value lies in its success in adding to its reserves base. Total reserves decreased by less than 5% in the period, following additions which accounted for a 3% replacement of the 3.7 MMboe reserves produced in the year. Reserves of 0.1 MMboe were added following performance driven reassessment of Hungarian reserves.

12 10 At a glance Our resources This is how we organise our people and resources Group Operations Employee profile Ukraine Operational staff 583 Offices: Kiev Poltava Sokolova Balka Workforce % locally employed 98% JKX Oil & Gas plc Group staff 21 Operational staff 738 Russia Operational staff 151 Offices: Moscow Maikop Koshekhabl Workforce % locally employed 91% Rest of World Operational staff 25 Offices: London Tbilisi Amsterdam Workforce % locally employed 97%

13 JKX Oil & Gas plc Annual Report & Accounts and the investment we make to ensure we deliver our objectives Outcome Ratio Male Female 79% 21% Ratio Male Female 78% 22% Ratio Male Female 78% 22% 2010 training investment $66, training investment $35, training investment $27,500 We develop strong local presences, drawing on extensive industry and country-specific knowledge to deal with the local operating environment. We have proven expertise in efficient oil and gas production and also the practical, on-the-ground experience of working where there can be a significant bureaucratic element in how everyday business is conducted. Across the lifecycle of each project, from first exploration to abandonment, we focus on having the right people with the right skills in the right place at the right time. Although we use expatriate teams during the formative stages of a project, over time their numbers will reduce significantly and the operation will ultimately rely on a high percentage of local employees. The training of local staff underpins our strategy and is an important aspect of how we do business.

14 12 At a glance Our performance and this is our performance during 2010, from a financial perspective. Total Second half First half Total PRODUCTION SUMMARY Production Oil (Mbbl) 1, ,457 Gas (Bcf) Oil equivalent (Mboe) 3,768 1,652 2,116 4,258 Daily production Oil (bopd) 3,049 2,371 3,740 3,991 Gas (MMcfd) Oil equivalent (boepd) 10,324 8,980 11,689 11,665 Total Second half First half Total $m $m $m $m OPERATING RESULTS Revenue Oil Gas Other Cost of sales Operating costs (17.9) (5.6) (12.3) (20.6) Depreciation, depletion and amortisation oil and gas assets (33.2) (14.7) (18.5) (32.8) Production based taxes (5.2) (2.6) (2.6) (4.0) (56.3) (22.9) (33.4) (57.4) Provision for impairment of fixed assets/write off of exploration costs (13.7) (5.8) (7.9) (5.0) Exceptional item impairment of Russian assets (74.6) (74.6) Total cost of sales (144.6) (103.3) (41.3) (62.4) Gross profit/(loss) 48.3 (14.9) Operating expenses Administrative expenses (25.3) (13.8) (11.5) (14.7) Gain/(loss) on foreign exchange (2.6) 0.5 (3.1) (2.3) Profit on sale of assets 2.5 Operating profit before exceptional item Operating profit/(loss) after exceptional item 20.4 (28.2)

15 JKX Oil & Gas plc Annual Report & Accounts Total Second half First half Total EARNINGS Net profit/(loss) ($m) 21.2 (13.9) Basic weighted average number of shares in issue (m) Earnings per share before exceptional item (basic, cents) Earnings per share after exceptional item (basic, cents) (8.34) Earnings before interest, tax, depreciation and amortisation ($m) 55.8 (12.4) Total Second half First half Total REALISATIONS Oil (per bbl) $69.15 $74.29 $65.97 $53.90 Gas (per Mcf) $7.59 $7.79 $7.41 $7.19 Total Second half First half Total COST OF PRODUCTION ($/boe) Operating costs $4.74 $3.36 $5.81 $4.85 Depreciation, depletion and amortisation $8.82 $8.92 $8.74 $7.71 Production based taxes $1.39 $1.61 $1.21 $0.93 Total Second half First half Total CASH FLOW Cash generated from operations ($m) Operating cash flow per share (cents) Total Second half First half Total BALANCE SHEET Net cash ($m) Net cash to equity (%) Return on average capital employed (%) 4.9 (6.0) Additions to property, plant and equipment/intangible assets ($m): Ukraine Russia Other Total

16 14 Chairman s statement Chairman s statement Sir Ian Prosser Chairman

17 JKX Oil & Gas plc Annual Report & Accounts 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. Annual dividends declared (pence) Held Earnings per share before exceptional item (basic, cents) -12% Exceptional item: cents 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 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 AIFR (All Injury Frequency Rate) figures decreased in 2010 and are well below the industry benchmark. Furthermore, we were successful in our attempt to achieve ISO 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 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.

18 16 Chief Executive s statement Chief Executive s statement Dr Paul Davies Chief Executive

19 JKX Oil & Gas plc Annual Report & Accounts 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 locallybased and managed operating subsidiaries led by skilled and committed teams. Production volumes (boepd) -11% 12,579 11,146 11,665 11,012 10, Net cash from operating activities ($m) -7% 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 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 Increase production at Rudenkovskoye from 2% of JKX s Ukrainian production in 2009 to 25% in 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 longterm 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 to start initial 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 a non-operator, have

20 18 Chief Executive s statement progressed well with production increasing in Hajdunanas 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 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 stepchange in performance during the coming 12 months. We are confident that 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 will play an important role in helping us reach 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.

21 JKX Oil & Gas plc Annual Report & Accounts Delivering our strategy Objectives for 2010* Achievements of 2010 Objectives for 2011 Commence development of the Rudenkovskoye field in Ukraine. Construct, install and commission an LPG facility in Ukraine. Accelerate the workover programme in Russia. Test additional wells in Russia. Construct and commission the gas facility at Koshekhablskoye in Russia, with delivery in third quarter 2010 followed by installation in the fourth quarter. Double reserves and production in Hungary. Continue to develop the exploration portfolio, particularly in Hungary, Bulgaria and Slovakia. Completed and tested horizontal well R-103. Design and fabrication completed; installation commenced. Workover activity throughout the period with up to three rigs contracted. Oxfordian well-20 tested. Fabrication completed and shipping to Russia commenced. Site preparation complete and installation commenced. Hajdunanas production replaced by Nyirseg reserves. Production in period up 97%. Exploration wells drilled in Hungary and Bulgaria. Seismic acquired in Hungary, Slovakia and Ukraine. Design/perform multi-frac of 1km horizontal wellbore of well R-103. Delivery, hook-up, commissioning and start-up. Complete workover of Callovian well-09 and deepen well-22 to Callovian. Test Oxfordian well-25 and Callovian wells 09 and 22. Complete installation, hook-up, testing and commissioning of facility; start-up of production. Add reserves and double production. Continue to develop exploration portfolio in Hungary, Ukraine, Slovakia and Bulgaria. *As set out in the 2009 Annual Report.

22 20 Operational review Operational review UKRAINE Our main Ukrainian interest is the Novo-Nikolaevskoye complex in the Poltava Oblast, eastern Ukraine. The complex is shown graphically below, with a NW/SE cross section of the fields in the licence complex. Novo-Nikolaevskoye complex All measurements are in Kilometres. Devonian Clastics Visean Basement Tournasian Carboniferous Clastics Salt

23 JKX Oil & Gas plc Annual Report & Accounts Ukraine update Completed: We carried out appraisal drilling in the Rudenkovskoye licence and completed the R-103 horizontal well. A second rig was mobilised, albeit later than scheduled. Planned: Drilling and workover activity will continue and we expect to reassess the reserves in the Ignatovskoye, Molchanovskoye and Novo-Nikolaevskoye fields towards the end of the year. Completion of the LPG plant at Poltava is on target for June Kiev Elizavetovskoye Novo-Nikolaevskoye Complex THE BLACK SEA The year saw an extension of our Ukrainian development programme, with the focus on appraisal drilling in the Rudenkovskoye licence together with important progress on recompletions and stimulations. During 2010, we carried out a range of activities to drive value from our production licences. The key focus of the 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 the second rig completing only one additional well during the fourth quarter. The programme of recompletions and stimulations continued throughout the period to maintain production levels in the Ignatovskoye and Molchanovskoye North. 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. In summary, PPC: Drilled, tested and/or completed a total of six 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, three well repairs, three fishing operations and two well abandonments. Commenced installation of the LPG recovery plant. Continued to upgrade and de-bottleneck the production facility. Installed additional generating and compression facilities. Ukrainian Reserves No reserves reassessments took place in Drilling and workover 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. Ignatovskoye LICENCE AREA 25.3 km 2 Remaining reserves as at 31st December 2010 Proved Probable Prov+ Prob Oil (MMbbl) Gas (Bcf) Oil + Gas (MMboe) 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

24 22 Operational review Ukraine continued 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 therefore be oil or gas bearing. Reservoir quality in the Devonian sandstone and Visean reef is generally good whilst both the Tournasian sandstone and limestone are variable and often dependent on local depositional and tectonic influences. Stimulation in these reservoirs is usually necessary and, although this can give high initial flow rates, the rates often decline to more modest levels. No additional wells were drilled or recompleted on the main structure of the field during the period. 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 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. Problems recovering the tubing resulted in work being suspended until Well I-110 was recompleted from the depleted Tournasian sandstone to the Tournasian carbonate. A similar recompletion 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. Molchanovskoye North & Main LICENCE AREA 7.9 km 2 Remaining reserves as at 31st December 2010 Proved Probable Prov+ Prob Oil (MMbbl) Gas (Bcf) Oil + Gas (MMboe) The Molchanovskoye production licence is located approximately 8km to the south of the Ignatovskoye Field and contains the southernmost producing field within the complex. The licence now comprises two distinct field areas: Molchanovskoye North and Molchanovskoye Main. 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

25 JKX Oil & Gas plc Annual Report & Accounts 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 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 1sq.km block. A second well in the block is tentatively planned for later in No reserves are currently attributed to this area of the field complex. Novo-Nikolaevskoye LICENCE AREA 7.8 km 2 Remaining reserves as at 31st December 2010 Proved Probable Prov+ Prob Oil (MMbbl) Gas (Bcf) Oil + Gas (MMboe) 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 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 Three further wells are planned for 2011 with the first well (N75) scheduled to spud in the third quarter.

26 24 Operational review Ukraine continued Rudenkovskoye LICENCE AREA 86.0 km 2 Remaining reserves as at 31st December 2010 Proved Probable Prov+ Prob Oil (MMbbl) Gas (Bcf) Oil + Gas (MMboe) The Rudenkovskoye production licence is the most northern of the four production licences. Reservoirs in the licence are the Tournasian 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 : Well R-103, 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 has 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 R-102, was drilled in early 2007 in the southern area of the field. It found two main gasbearing zones in the Devonian sandstone but the presence of water precluded any fracture stimulation testing in the lower interval. 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 four-fold 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, including: 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 during the year. 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.

27 JKX Oil & Gas plc Annual Report & Accounts Zaplavskoye The Zaplavskoye exploration licence is adjacent to the Molchanovskoye production licence and now comprises an area of 137.6sq.km. The permit has been extended for a further five years until In addition, the area has been extended by 41.9sq.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 100km 2-D seismic programme was shot in late 2010 ahead of exploration drilling planned for 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. Chervonoyarske East The Chervonoyarske East exploration licence was acquired in December 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 42sq.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 Elizatovskoye The Elizavetovskoye exploration licence is located in the central part of the Dnieper-Donets basin and covers an area of 70sq.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 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.

28 26 Operational review RUSSIA The Koshekhablskoye field is located in the southern Russian autonomous Republic of Adygea. The licence covers an area of 32.7sq.km The field is shown graphically below, with a NW/SE cross section. Koshekhablskoye field All measurements are in Kilometres. Oxfordian Gas Reservoir Middle Jurassic Cretaceous Upper Jurassic Callovian Gas Reservoir

29 JKX Oil & Gas plc Annual Report & Accounts Russia update Completed: We initiated and in many cases completed a range of workovers, tests and fishing operations. The GPF plant was fabricated and shipped, with installation well underway before the year-end. Planned: First commercial gas production is scheduled for the Autumn. We aim to have three wells in production at start-up, with further wells being brought on-stream in THE BLACK SEA Koshekhablskoye Maikop Koshekhablskoye LICENCE AREA 32.7 km 2 Remaining reserves as at 31st December 2010 Proved Probable Prov+ Prob Oil (MMbbl) Gas (Bcf) Oil + Gas (MMboe) JKX completed the purchase of Yuzhgazenergie LLC ( YGE ) in November 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 32.7sq.km. The field was discovered in 1972 and produced a total 89 Bcf of gas before operations were suspended in January 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 of 2011, delayed from our previous mid-year target. During the period, YGE: 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 Recovered tubing from the Callovian appraisal Well-09 to a depth of 5,312m using the

30 28 Operational review Russia continued 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 autumn 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 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 this 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. 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 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 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 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. Right: Since year-end 2010 the pace of the Gas Processing Facility construction has increased significantly, as pre-constructed components have arrived on-site.

31 JKX Oil & Gas plc Annual Report & Accounts

32 30 Operational review HUNGARY Within our Hungarian portfolio all production currently comes from the Hajdunanas area of the Hernad/ Nyirseg licences. The Hajdunanas area is shown graphically below, with a N/S cross section. Hernad field All measurements are in Kilometres. Middle Miocene Gas Reservoir Oil Reservoir Gas Reservoir Upper Miocene

33 JKX Oil & Gas plc Annual Report & Accounts Hungary update Completed: Our operations progressed well with production increasing in Hajdunanas supported by the tie-in of the Gorbehaza-1 discovery. Gas has been tested in the Tizsavasvari-6 and Nyekpuszta-2 exploration wells. Planned: Together with the field operator, we are planning a 20% increase in production at Hajdunanas during the second quarter of the year. Further appraisal of the Tizsavasvari-6 and Nyekpuszta-2 exploration wells are scheduled for Hernad Budapest Turkeve Veszto Hernad LICENCE AREA 5,410 km 2 Remaining reserves as at 31st December 2010 Proved Probable Prov+ Prob Oil (MMbbl) Gas (Bcf) Oil + Gas (MMboe) JKX holds 50% equity in the northern Pannonian Basin Hernad licences in a joint venture with the operator, Hungarian Horizon Energy ( HHE ). The Hernad I licence covers 2,903sq.km and the Hernad II licence covers 2,507sq.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 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 Nyirseg licence has been tied in the Hajdunanas 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, 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 Hajdunanas reserves in 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 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 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

34 32 Operational review Hungary continued 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 12km from the Hajdunanas field, remains suspended as an oil discovery, pending a forward programme of formation stimulation. A further 300sq.km 3D seismic data acquisition is planned for the Jaszsag area in the south of the Hernad II licence during the first half of Nyirseg JKX farmed-in for a 33.3% interest in 120sq.km of the adjacent Nyirseg licence operated by PetroHungaria in late JKX subsequently increased its holding to 50%, as did HHE, by buying out the minority partners. The first well Gorbehaza-1 tested 3.74 MMcfd of gas and 20 bcpd and has been tied into the Hajdunanas gas production facility some 2.5km away. First gas was achieved in August 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 In March 2009, JKX farmed-in for a 25% interest in a 15.6sq.km area of the Veszto exploration licence held by HHE in the eastern Pannonian Basin. A 3D seismic survey covering the entire 219sq.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 The well encountered a gross hydrocarbon column of 85m and was fracture stimulated and tested in 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 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 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.

35 JKX Oil & Gas plc Annual Report & Accounts REST OF WORLD Bulgaria JKX (40% and operator) operates two onshore exploration permits, B Golitza and B1 Golitza, covering a total of 3,355sq.km in eastern Bulgaria. The licences include the area of the Kamchia Trough, an onshore extension of the Tertiary age western Black Sea Basin, which is now the subject of renewed deepwater exploration activity. The 2009 seismic data acquisition of 250sq.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 third quarter of 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. Slovakia In 2008, the Company farmed-in for a 25% interest in the Svidnik, Medzilaborce and Snina exploration licences, covering a total area of 2,278sq.km in the Carpathian Fold Belt in north east Slovakia. Acquisition of 346km 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 Further regional seismic data acquisition is planned for the third quarter of 2011.

36 34 Financial review Financial review Bruce Burrows Finance Director

37 JKX Oil & Gas plc Annual Report & Accounts 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. Revenue oil ($m) +3% Revenue gas ($m) -4% 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 cents per share (2009: cents per share) or, excluding the impact of the impairment provision, was 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 $17.9m (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 up 13% (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 below and within note 5(e) and 5(f) of the financial statements. 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 Yuzhgazenergie (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.

38 36 Financial review Financial review continued 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 the anticipated convergence of Adygean gas prices to net back European levels is now delayed to The current level of gas prices in Russia are also lower than those anticipated in March 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 have 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 $74.6m Russian asset exceptional item; the recognition of a deferred tax asset in the UK; and reduced current tax on core Ukrainian operations resulting from reduced taxable income. Dividend The Board proposes a final dividend of 2.6 pence per share (2009: 2.7 pence per share) giving a full year dividend of 5.0 pence per share (2009: 5.0 pence per share). The proposed dividend will be recognised when paid. The Board has decided that not increasing the full year dividend is appropriate, following the continued extensive capital investment in the Group s YGE redevelopment project in southern Russia, coupled with the cash impact of rental payments in Ukraine following the 1st January 2011 introduction of Ukraine s new tax code. Realisations Oil ($ per bbl) +28% Realisations Gas ($ per Mcf) +6% Maturity of financial liabilities Less than Between Between Over 1 year 1 and 2 years 2 and 5 years 5 years $000 $000 $000 $000 At 31st December 2010 Trade and other payables 51,369 Deferred consideration, due within one year 2,000 53,369 At 31st December 2009 Trade and other payables 36,018 Deferred consideration, due after one year 5,000 41,018

39 JKX Oil & Gas plc Annual Report & Accounts Net profit before exceptional item ($m) -5% Production costs ($ per boe) -2% Exceptional item: $60.1m (net of tax effect) 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, Capital expenditure Total capital expenditure increased in 2010 by 66%. The mix reflects the increased investment in the Group s Russian project which accounted for 60% of total investment (2009: 39%). Russia $107.8m 60% Total: $178.5m Rest of world $4.7m 3% Hungary $9.9m 6% Ukraine $56.1m 31% 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 instruments The Group s financial instruments comprise cash and liquid resources, various items such as trade and other receivables, and trade and other payables that arise directly from its operations. The main purpose of these financial instruments is to finance the Group s operations. Foreign exchange risk sensitivities If as at 31st December the Ukrainian Hryvna had strengthened/ (weakened) by 10% against the US Dollar with all other variables held constant, post-tax profit for the year would have been $0.4m (2009: $0.1m) higher/lower, mainly as a result of Hryvna denominated gas trade receivables, cash balances and trade payables, and the foreign exchange in equity would have been $0.1m higher/lower (2009: remained the same). If as at 31st December the Russian Rouble had strengthened/ (weakened) by 10% against the US Dollar with all other variables held constant, equity would have increased/decreased by $0.5m (2009: $0.1m) mainly as a result of cash balances and trade payables. If as at 31st December the Euro had strengthened/(weakened) by 10% against the US Dollar with all other variables held constant, post-tax profit for the year would have been $0.3m (2009: $0.1m) higher/lower, and the foreign exchange in equity would have increased/decreased by $0.7m (2009: $0.1m) mainly as a result of trade receivable and cash balances. If as at 31st December Sterling had strengthened/(weakened) by 10% against the US Dollar with all other variables held constant, post-tax profit for the year would have been $2.5m (2009:$4.7m) higher/lower, mainly as a result of Sterling denominated trade receivables, cash balances and trade payables, and the foreign exchange in equity would have been $2.0m (2009:$0.3m) higher/lower. Fair value interest rate risk sensitivities At 31st December 2010, if interest rates had increased by 10% with all other variables held constant, post-tax profit would have remained the same (2009: remained the same).

40 38 Financial review Risks we face and how we manage them The Group s business of oil and gas exploration and production and its chosen area of operation, central and eastern Europe, dictates that it is exposed to a broad range of risks. The Group s approach to this spectrum of risk is to monitor and mitigate identified risks and then actively manage them to the extent possible to minimise potential adverse effects on the Group s financial performance. Risk management is carried out by designated individuals under policies and procedures approved, reviewed and managed by the Board of Directors. An annual review of the Group s system of internal control is What s the risk? Definition Probability Reservoir performance The hydrocarbon reservoirs that generate production and cash flow to underpin the Group s growth may not perform as expected, exposing the Group to lower profits and challenges in funding planned development. Accordingly, forecast reservoir performance is critical in deciding on development options for specific assets, as well as allocation of resources generally across the Group. MED Capital expenditure The Group operates in a capital intensive business requiring long lead time investment decisions. Deviations in forecasts of timing and quantum of exploration and development expenditures can expose the Group to funding challenges and to projects which may have diminished or negative economic return. Such deviations can result from a number of causes, including general economic and industry specific cost inflation, variations in foreign exchange rates, deficient project planning and monitoring of project spend. MED Commodity prices The Group is exposed to international oil and gas price movements. The Group is a price taker and does not enter into hedge agreements unless required for borrowing purposes. MED Procurement and contract management Inability to negotiate and manage purchases and contracts can increase costs to the Group and/or cause delays to project completions and operations, negatively impacting production, cash flow and value generation. LOW Capital management An optimal capital structure should be maintained for the Group to continue maximising returns for shareholders and benefits to other stakeholders. Failure to manage the capital structure could reduce stakeholder returns and, in extreme circumstances, impact the Group s ability to operate as a going concern. LOW

41 JKX Oil & Gas plc Annual Report & Accounts conducted by the Audit Committee, along with a review at each meeting of the Audit Committee of the Group risk landscape and management. Potential impact How we manage it HIGH As it has evolved, the Group has continued to recruit specialist and industry recognised personnel and consultants to model, monitor and manage reservoir performance. Increased levels of local operating experience both within and external to the Group assist in further mitigating this risk. The Group manages its key activities in Ukraine and Russia via strong local operating companies that have been developed and staffed with skilled personnel. The interaction between local and London based specialists and third party consultants is key to operational risk management. The continued intraregional diversification of interests (highlighted by Russian and Hungarian development participations) has aided in spreading this risk away from the previous very high concentration in Ukraine. With the increased diversification in assets, the Group has also expanded its UK technical team to ensure knowledge transfer to and between operating companies and the consistent application of the Group s strategic technical methodology. MED The Group operates its key interests in Ukraine and Russia via strong local operating companies, who interact with London based Group specialists, as well as UK and locally based contracted specialists to maximise project management capability. For individual capital projects which are material to the Group, Project Management teams are created to oversee planning and implementation. Recent examples of such teams include those established at the Rudenkovskoye development in Ukraine, and at the Koshekhablskoye workover programme and gas processing facility construction in Russia. These project management teams report to stakeholder groups comprising senior management and other appropriate project related staff and contractors. MED Most of the Group s gas sold in Ukraine and its share of Hungarian gas sales is through market related contracts to significant and creditworthy customers. This is intended to minimise exposure to abrupt price movements, ensuring sales are as closely matched as possible, in terms of timing and volume, to production. The balance of oil and gas production in Ukraine is sold by way of auctions, conducted with a frequency aimed to achieve as close as practicable the aforementioned matching principle. The Group s Russian gas production, scheduled to commence in autumn 2011, is intended to be sold on a similar basis to the bulk of Ukranian production, being to large credit worthy customers on contracts at market related prices. LOW The Group operates policies, procedures and controls intended to regularise procurement within strict levels of delegated authority. All significant purchases are tendered. Each operating entity manages a schedule of approved suppliers. All contracts are constructed specifically or in accordance with templates, targeted at the jurisdictions of supply and delivery, taking account of reviews of both internal lawyers and, where dictated by procedure, by third party legal advisors. HIGH Capital management is monitored by the Finance Director in accordance with policies and procedures approved by the Board. It is also assessed and monitored by the Group s financial advisor and by the Board. In order to maintain or adjust the capital structure, the Group may adjust the amount of dividends paid to shareholders, return capital to shareholders, issue new shares, sell assets, or obtain borrowings from third parties. Two recent material examples of managing the Group s capital structure have been the February 2010 share placing ($58.4m net) and the concluding of a $15.0m draw-down facility for PPC in Ukraine with Credit Agricole CIB Ukraine.

42 40 Financial review Risks we face and how we manage them continued What s the risk? Definition Probability Country exposure The Company operates in a variety of emerging markets where the accounting, tax and legal environment and the application of laws and regulations are constantly evolving. New laws can come into effect at times which can conflict with others and, therefore, are subject to varying interpretations and changes which may be applied retrospectively. This can result in the Group being subject to uncertainties relating to the determination of its tax as well as other liabilities. Management s interpretation of tax legislation as applied to the transactions and activities of the Group may at times not coincide with that of the tax authorities. As a result, the tax authorities in the countries of operation may challenge transactions and the Group may be assessed for additional taxes, penalties and fines which could have a material adverse effect on the Group s financial position and results of operations. MED Foreign exchange exposure The Group operates internationally and is exposed to foreign exchange FX risk arising from various currency exposures, primarily with respect to Ukrainian Hryvna and the Russian Rouble. FX risk arises from future commercial transactions, recognised assets/liabilities and net investments in foreign operations. LOW Cash flow and interest rate exposure The Group s income and operating cash flows are subject to changes in market interest rates. LOW Credit Credit risk arises from cash and cash equivalents and deposits with banks and financial institutions, as well as credit exposures to customers, including outstanding receivables and committed transactions. LOW Liquidity Reduction in liquidity and working capital could result in delay or cancellation of capital projects. In extreme circumstances, this could impact day to day operations and the Group s ability to continue as a going concern. LOW Health, safety, environment & community relations Failure to put in place and operate a rigorous HSEC regime can endanger and negatively affect stakeholders. Adverse publicity from any poor performance in this field could negatively affect the Group. The Group could be held responsible for addressing any contamination/damage to current or past licences and surrounding areas. The associated cost could be significant. LOW Production licences The Group operates in a region where title to licences can be challenged by state and non-state parties. If a licence title is challenged, production could be suspended or terminated depending on the outcome. Such challenges may emanate from licence provenance or compliance with licence commitments. LOW

43 JKX Oil & Gas plc Annual Report & Accounts Potential impact How we manage it HIGH The Board and management recognise the constant need for expert advice to ensure full compliance with local and international regulations and laws. Our strategy is to employ skilled local staff in the countries of operation and provide them with ongoing training opportunities. In addition to such specialist staff employed in the Group s operating entities, the Company has established legal, tax and accounting advisors. In Ukraine, PPC has at times since 1994 sought clarification of its status regarding a number of production related taxes and has been subject to a number of such taxes. Specifically, application of production related tax pre 2009 has attracted scrutiny. This risk is further described in note 21 of the accounts. On 1st January 2011 a new tax code became effective in Ukraine replacing most of the previous tax laws. The new tax code has removed uncertainty over the applicability of rental fee payment by PPC from 2011, and accordingly PPC has been liable to and is paying such fees. LOW By matching, as far as is practicable, receipts and payments in the same currency and by following a range of commercial policies to minimise exposure to the Hryvna denominated sales, which continued to account for more than 90% of Group revenues in LOW Interest rates are continually monitored by the Finance Director. The Treasury sub-committee of the Audit Committee also reviews rates on a regular basis, as well as the Group s strategy with regards to cash deposits. This strategy, given the current banking environment, is focused on security of deposits (through bank selection and monitoring criteria) in preference to maximising interest rate return, a strategy which is regularly reviewed. LOW Credit risk on cash and cash equivalents is managed at a Group level through two Treasury Committees: one comprises management, which meets weekly, while the other is a sub-committee of the Audit Committee. These Committees evaluate the relative risks of banks and determine the appropriate allocation of Group funds across a range of banks in varying jurisdictions, with the aim of minimising credit risk associated with cash deposits. Local customers are managed at local level if there is no independent rating, the Group evaluates their financial position, past experience and other factors. Management does not expect any losses through non-performance by counterparties. The Company does not have any concentration of credit risk and management does not consider there to be any significant exposure to material loss. HIGH Management monitors rolling forecasts of the Group s liquidity on the basis of expected cash flow to ensure any remedial action can be taken with as much lead time as possible. The table on page 36 analyses the Group s financial liabilities into relevant maturity groupings based on the remaining period at the balance sheet to the contractual maturity date. HIGH The Group treats HSEC as a priority and has a London based HSEC manager who reports directly to the CEO. In addition, HSEC managers within local operations engender a safe operating environment. Significant expenditures are incurred to comply with applicable laws and regulations and to the extent reasonable practicable, create social and economic benefit in the surrounding area. Appropriate insurances are maintained to manage the Group s financial exposure. HIGH The Group conducts rigorous due diligence on licence title as part of any review of prospective interest acquisitions. For licences held, the Group ensures compliance with all commitments and where commitment adherence is for whatever reason likely to be out of time or scope, extensions/waivers as required are obtained from relevant authorities. Identification of any such potential infringement of commitments is ensured through rigorous project and company procedures and controls.

44 42 Corporate Social Responsibility review Corporate Social Responsibility review We aim to be a good corporate citizen, supporting our people and their communities, and minimising our environmental impact. The highlights of 2010 include: Improving our health and safety record, with a decrease in the AIFR (All Injury Frequency Rate) Working for 1,000,000 man-hours at Koshekhablskoye, Russia with no Lost Time Injuries (LTI) Working for 1,500,000 man-hours at PPC, Ukraine with no LTI Achieving ISO Environmental accreditation Maintaining OHSAS Health & Safety accreditation Improvement plan for our Carbon Disclosure Project reporting CSR informs everything that we do Our people, the environment and the communities where we operate are the keys to our business. We manage our business with due regard to our stakeholders best interests, and are committed to being recognised as a good corporate citizen and neighbour. We strive to support our people at work as well as in their broader lives and also to minimise our impact on the environment. Corporate Social Responsibility (CSR) informs all areas of our operations and is led by the Chief Executive Officer. Our Health, Safety, Environment and Community (HSEC) manager reports directly to the CEO and has responsibility for creating a framework and maintaining the HSEC Management System for the management of the Group s non-financial impacts. The Board is provided with quarterly updates relating to the major CSR issues. A management review of all HSEC systems is carried out every year: a full Board-level review of progress was completed in December 2010 and plans were agreed for These plans include a renewed focus on continuous improvement and on making sure that all staff are aware of key HSEC issues. At JKX, we believe in running operations at a local level wherever possible. Accordingly, a nominated individual has executive responsibility within each operating company for HSEC. These representatives are fully trained and experienced as well as being familiar with local culture, regulations and working practices. For example, for the Koshekhablskoye project we have recruited and trained a full team which is now delivering a high standard of HSEC management. To ensure Group-wide consistency, our operationally-based teams report not only to the general director of the local operating company but also liaise with the Group HSEC manager. Rigorously applying policies and standards We have robust processes in place to oversee our CSR commitment. Our aim is to comply with all local laws and regulations as a minimum and to exceed them where possible. We expect our partners to reach the same standards. Our policies and standards cover: Safety reporting and incident management. Exposure man hours. Occupational health provision and record keeping. Environmental reporting and incident management. Behavioural based safety programmes. Continuing Professional Development and implementation. Human resources practices, covering areas such as equal opportunities. Handling of charitable requests. Local community relations. Reporting to local and UK authorities. Open and transparent We have an open and transparent culture, one that encourages people to report every incident, in order that we can learn from our experiences and improve our safety performance. If they prefer, workers are able to report incidents anonymously via post-boxes. Corporate CSR objectives Protect people by providing information and advice; promoting and assuring a goal-setting system of compliance. Influence stakeholder organisations to embrace high standards of HSEC and to recognise the social and economic benefits. Seek to optimise the use of resources to deliver our mission and vision, and enhance our reputation as a good corporate citizen. Develop new ways to establish and maintain an effective HSEC culture in a changing economy, so that all employers take their responsibilities seriously, the workforce is fully involved and risks are properly managed. Exemplify Oil and Gas sector best practice in managing our resources. Achieve higher levels of recognition and respect for HSEC as an integral part of a modern, competitive business. Continue to work with the business to prevent catastrophic failures in major hazard industries. Undertake and encourage research, and enforce the law where necessary.

45 JKX Oil & Gas plc Annual Report & Accounts Targets 2010 Achievements 2010 Targets 2011 Reduce the AIFR by 5%. Meet or exceed the HSEC performance benchmark set by the Association of Oil and Gas Producers (OGP). Prepare PPC for OHSAS accreditation. Prepare JKX for ISO accreditation. Maintain OHSAS accreditation. Complete and implement the Carbon Management Plan. Achieved. The AIFR for 2010 was 0.62 compared to 1.5 in Achieved. The OGP benchmark was 3.4. Achieved, with the first assessment due in Q1 of Achieved. Achieved. Achieved. Our reporting standards were assessed by the Carbon Disclosure Project. Reduce the AIFR to 0.4. Meet or exceed the benchmark set by the OGP for Complete OHSAS accreditation for PPC. Maintain and enhance ISO accreditation. Maintain and enhance OHSAS accreditation. Carry out new baseline study in 2011 and update the Carbon Management Plan to include new projects. Introduce BBS/Health monitoring /COSHH initiatives. Identify opportunities to improve training and competence assurance. Identify opportunities to improve consultation and Community Liaison Plans. Seek opportunities for improved contractor selection and management support. Improve contractor risk based approach to HSEC Management. Identify opportunities for improved Risk Management and Assessment activities. Examine opportunities to improve waste disposal and recycling. Identify opportunities to improve the contribution of local HSEC staff. Identify opportunities for improved hazard, near-miss and incident reporting. Identify opportunities to improve Emergency Response plans. In progress. In progress. In progress, with high levels of communication established at Koshekhablskoye. In progress. Auditing and sampling have been carried out. A programme of management site visits and training plans have improved contractor efforts in Achieved, with greater participation from local staff in the HAZOP process during Achieved, following discussions with operational locations and the development of plans to identify reductions for Achieved, with improvements to risk assessment techniques matched by better dissemination of information and consultation between locations by local HSEC staff. Achieved. Achieved, with improved emergency response arrangements at PPC backed by closer collaboration with the Ministry of Emergency Response in the Ukraine. Continue to improve the systems and increase awareness and training. Continue to improve and identify opportunities for improvement in competence and training, with particular emphasis on the Koshekhablskoye and the Ukrainian LPG projects. Continue to improve and identify opportunities for improvement in Community Liaison Plans with a particular focus on Koshekhablskoye. This is an ongoing initiative for 2011 and beyond, as new contractors or processes are introduced. This is an ongoing initiative for 2011 and beyond as new contractors or processes are introduced. This area is to be managed carefully during precommissioning and start-up at Koshekhablskoye. This is an ongoing initiative for 2011 and beyond as new processes are introduced, mainly on the Koshekhablskoye and the Ukrainian LPG projects. This will continue to be monitored and continuously improved throughout 2011 and beyond. Continually improve the contribution of local HSEC staff. Continue to improve reporting, using workshops, site campaigns, training sessions, tool-box talks and briefings. Further improve plans. We have already reviewed the plans for Hungary, and enhancements are planned for Russia in 2011.

46 44 Corporate Social Responsibility review CSR case study Koshekhablskoye, Russia Health and safety We will never compromise the safety of our people. The project poses significant challenges to our workforce, including the presence of Hydrogen Sulphide (H 2 S). We enhanced the level of protection from H 2 S during 2010 and worked more than 1 million man-hours without a Lost Time Injury. Environment Waste management is a challenge in an area that has limited infrastructure for safe waste disposal. In addition to introducing a reduce, reuse, recycle scheme at the project, we are utilising temporary options such as storage while working with local industry to create a permanent solution to the issue of waste. Employment We are bringing valuable jobs to the region. The current number of YGE employees is 155, which is expected to peak at over 250. The project is also generating employment for contractors and supply chain vendors: the number varies but could be up to 600 support and associated personnel. Community We are keen to be good neighbours and to play our part in the local community whenever possible. In 2010, we were pleased to provide financial and practical support to the town of Maikop s Harvest Festival celebration, which is an important event in the lives of the community. At Koshekhablskoye, some 1,500km south of Moscow, we are building a gas plant which has major implications for our four CSR pillars: health and safety, employment, community and the environment. A top priority for us is to deliver the project to its full potential while also ensuring that it provides benefits to the local people and their community. The nearest town, Maikop, is the capital of the Adygea Republic and is recognised as one of the most attractive cities in the Northern Caucasus. However, it is also an area of above average unemployment. The local people need jobs but they also need them to be good, long-term and well-paid jobs provided within an effective HSEC framework. Our goal is to be a net contributor to the local community and to build a reputation as an important and positive influence. We can help drive social and economic development in local communities through the use of our resources and through our supply chain network. We used extensive consultation, which included hosting a public meeting, to gather opinions and provide the community with information on the project. In particular, we explained how we can contribute to initiatives and events which support local companies and employment, develop skills and encourage entrepreneurship. We also carried out an Environmental Impact Assessment (EIA) with the Volgograd Design Institute. Our activities will result in higher-risk environmental

47 JKX Oil & Gas plc Annual Report & Accounts challenges, particularly in terms of water use and waste management. To address this, we are implementing systems to ensure minimal water use, minimal waste generation and that we have a clear baseline against which to measure our performance. An Oil Spill Contingency Plan (OSCP) has been prepared to ensure rapid and appropriate action in the event of a spill. Oil spill contingency training is planned for 2011 for YGE employees. Construction at Koshekhablskoye is continuing at pace, with first commercial gas production on target for YGE, our operating company, currently employs 155 people, with this set to rise to over 250. The number of contractors and supply chain vendors will vary but we expect it to peak at up to 600 support and associated personnel. Their health and safety at work is very important to us. The Koshekhablskoye project poses a number of HSEC challenges, notably through the presence of Hydrogen Sulphide (H 2 S), an extremely dangerous substance which can cause fatalities if not addressed correctly. Although H 2 S controls were already in place to meet legal requirements, the JKX Technical Director and the YGE Managing Director demanded greater protection for the workforce. We have now carried out a full review and introduced enhanced precautions covering such issues as training, additional H 2 S monitoring, enhanced drills and evacuation plans, and emergency response plans.