JKX.L Regulatory News (JKX)

JKX Oil & Gas plc

('JKX' or the 'Company')

FINAL RESULTS

 FOR THE YEAR ENDED 31 DECEMBER 2013

Key Financials

· Revenue: $180.7m (2012: $202.9m)

· Profit from operations before exceptionals: $9.2m (2012: $51.6m)

· Profit from operations after exceptionals: $9.2m (2012: $5.8m)

· Earnings per share: 3.78 cents (2012: loss per share 6.59 cents)

· Operating cash flow: $74.8m (2012: $109.3m)

· Capital expenditure: $64.4m (2012: $67.3m)

· Cash resources and undrawn bank facilities: $40.9m (2012: $12.7m)

Outlook

· Continued production growth with an increasing Ukrainian contribution

· Fully funded development programmes in Ukraine and Russia through 2014

· Expectation for gas realisations in Ukraine to remain stable and gas realisations in Russia to rise

· Elizavetovskoye field growth potential identified

· New prospects identified increasing potential to our existing licence portfolio

· Continued growth in Group reserves and resources expected in 2014

Commenting on the results, JKX Chief Executive Dr Paul Davies said: "We have delivered our targeted production growth and continued to build our reserve base, utilising our strong operating cash flow and the proceeds from our successful bond placement. This provides certainty of funding for our development and exploration programmes.

"We are refocusing our investment on Ukraine. We have made an important step forward in the development of our largest untapped gas resource with the successful multi-frac in the Rudenkovskoye field. We have also brought on-stream our Elizavetovskoye development which is performing above expectations.

This year has started well with two excellent well results on our Elizavetovskoye field. We are forecasting continued growth of production through 2014 with an increased contribution from Ukraine where gas realisations are expected to remain strong. JKX has operations in both Russia and Ukraine and our activities in both countries continue without disruption." 

ENDS

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CHAIRMAN'S STATEMENT

Fully funded developments and rising production

Your Company has achieved significant progress in 2013 with recommencement of development drilling in Ukraine and increased gas production in Russia. These achievements reflect the positive impact of the deployment of the $40 million funding secured early in the reporting period. The continuation into 2014 of our fully funded development programmes in Ukraine and Russia will lead to a further improvement in our stabilised production levels. Also, I am optimistic that in 2014 we will begin to see the potential of the new prospects within our existing licence portfolio which have been identified from the increase in seismic and data gathering activities during the period.

Oil, gas and LPG realisations in Ukraine during the period were stable and have continued at attractive levels into the first quarter of 2014. Strong cash flow from our Ukrainian production continues to underpin the Company's investment programmes and will continue to do so in 2014. We are monitoring the commercial market for our production closely as the impact of current political changes in the country becomes apparent. We remain of the view that disruption to our operations is unlikely, consistent with our experience of political change in the country during the last twenty years.

In Russia, improved levels of production up to plant capacity and above and improved levels of gas realisations have increased the contribution to Group cash flow. We continue to forecast an upward trend for gas realisations towards European netback convergence over the medium term, albeit at a somewhat slower rate than originally predicted. The objective for 2014 is the stabilisation of production levels to meet the projected stretched capacity of our Russian production facilities in the second half of 2014.

Strategy

Your Company's commitment to eastern and central Europe is not just a result of operating longevity in the area, but also our clear vision of the untapped potential for technically-led developments, coupled with a clear grasp of the political risk and commercial demands of working in emerging market economies. We are committed to the region for our on-going operations and their development and it remains our preferred area for expansion.

Poltava Petroleum Company ('PPC') is your Company's wholly-owned operating subsidiary in Ukraine. Its operations are located in central Ukraine in Poltava, 200 miles south-east of Kiev. We also have a wholly-owned operating subsidiary, Yuzhgazenergy ('YGE'), in the southern Russian Republic of Adygea. We are monitoring the current political situation between Ukraine and Russia carefully and I am pleased to confirm that there have been no disruptions to JKX's operations in either of our operating locations. In light of our experience of political change in the area over the past twenty years, we consider that disruption to our operations is unlikely and that, in the short term, political changes will not affect our traditional exploration and production markets. Our prospects in the longer term may be influenced by events as they unfold and we will inform shareholders of any changes if and when they occur. Our focus remains our staff and customers in Ukraine and Russia where all our oil and gas is sold to private sector buyers in their respective domestic markets.

In Ukraine, demand for our domestically produced oil, gas and LPG is unlikely to diminish with the country's significant deficit in its domestic oil and gas production levels expected to continue for the foreseeable future. In addition, the recent increased participation of the large multi-nationals in both tight gas and shale gas plays is to be welcomed both for the potential increased investment in the country and the stability it brings to the legal and commercial framework of the resources sector.

Growth in the independent gas sector in Russia continues, enabling our Russian subsidiary to benefit from a stable commercial market for gas sales and a constructive rapport with the state regulatory authorities. Good progress is being made on the initial stages of evaluating our large Georgievskoye exploration licence with its proximity to the Koshekhablskoye producing licence providing a solid platform to build on our position in the region.

The technical and managerial strength of our operating subsidiaries in Ukraine and Russia characterises the success of our overall development strategy in our chosen area. Our Ukrainian subsidiary, PPC, celebrated its 20th anniversary in January this year, an admirable achievement for the first independent oil and gas company in Ukraine. Certainly, the growing expertise and experience of our staff has been well demonstrated in the period with the successful execution in Ukraine of the largest onshore multi-frac in Europe to date, and the successful side-tracking and completion of a further high pressure and high temperature ('HP/HT') well in Russia at a depth below 5,000m.

The Company again demonstrated an excellent record in 2013 for health, safety, environmental matters and community liaison ('HSEC'). We experienced zero lost time injuries in 1.6 million manhours of safety exposure, and achieved injury and environmental incident frequency rates well below the industry benchmarks. I am also pleased to report that your Company's outstanding record in this critically important area has again been recognised with achievement of CSR World Leader status, and receipt of the International Corporate Social Responsibility Silver Award at the International CSR Excellence Awards 2013.

Performance

Group operations in Ukraine and Russia during the period resulted in a healthy rise in production, with Russian annual production exceeding Ukrainian production for the first time.

The Ukrainian exploration and development drilling programme at Poltava restarted in April and continued through the period. In the third quarter, we successfully completed the large multi-frac on well R-103 in the Rudenkovskoye licence and placed the well on production. The production facilities for the new Elizavetovskoye field development were completed on schedule at the end of the period with the first new well brought on-stream in January of this year at a significantly higher rate than predicted.

The Koshekhablskoye field in Russia completed its first full year of operation, with gas production reaching and even exceeding nominal plant capacity of 40MMcfd. Five production wells have now been re-completed, and should be sufficient to meet the planned 50% expansion of plant capacity in 2014.

The reserve review of our licence portfolio as of 31 December 2013 concluded that we have again increased our 2P reserve base. After a total 2013 production of 3.6 MMboe, the Group 2P reserves marginally increased to 94.2MMboe (a reserves replacement ratio of 112%).

Your Board

As reported in my last Annual Statement, Richard Murray joined the Board at the beginning of the period as non-executive director and Chairman of the Audit Committee. The Board has otherwise remained unchanged with five non-executive members and four executive members.

Dividend

The Board has continued to review the cash flow demands of the current capital programme and has concluded that it is not appropriate to recommend a dividend at this time. The Board will continue to review its dividend policy going forward.

Outlook

Activity levels in both Ukraine and Russia will remain high in 2014, but with our Ukrainian projects attracting increasing emphasis and share of Group capital expenditure. All capital programmes are adequately funded and underway, and the resulting rise in production is forecast to continue through 2014.

In Ukraine, the new Elizavetovskoye development is progressing well with the first two wells delivering gas at more than double their forecast rates. The ongoing development and expansion of this excellent asset is central to the projected rise in Ukrainian production this year. Further development and appraisal drilling is also planned for the Novo-Nikolaevskoye complex, including a new location defined by amplitude analysis of the recently acquired seismic on the Novo-Nikolaevskoye field and the next well on the Rudenkovskoye field. Finally, the water flood programmes on the Molchanovskoye and Ignatovskoye licences will begin implementation towards the latter part of the current period.

In Russia, tubing replacement in two of the five production wells in our Koshekhablskoye field is the priority for the first half of this year to be followed by the expansion of our Russian plant capacity. Again, increase in stabilised production is the focus of this year's activities.

Finally, I wish to thank all or dedicated staff for their commitment to the Company and its goals, and also to our shareholders for their continuing support.

Nigel Moore

Chairman

CHIEF EXECUTIVE'S STATEMENT

Increased activity leads to rising production

Our performance

Continuous development drilling and workover activity in Ukraine recommenced in the second quarter of 2013. Reservoir stimulation of the large deep, tight gas Rudenkovskoye field was undertaken at mid-year and development of the stand-alone Elizavetovskoye field facility completed by year end. In Russia, production from the Koshekhablskoye field reached plant capacity.

Average oil and gas production for the year increased by 18% to 9,731 boepd (2012: 8,281 boepd), with increasing production in Russia being the main driver of growth.

Group revenue for the year was lower at $180.7m (2012: $202.9m) and reflected both the interruption to our Ukrainian development drilling at the beginning of the period, but also the increased proportion of Russian gas with lower realisations within total Group production. LPG revenues in Ukraine were also lower at $13.9m (2012:$ 18.6m) as a result of lower Ukrainian gas production and reduced realisations in the period.

Operating profit after exceptional charges rose by 59% to $9.2m (2012: $5.8m).

Our progress

The successful placing of $40 million of convertible 5-year bonds early in the reporting period underpinned an increased level of development activity, leading to a rising level of Group production.

In Ukraine, six well work-overs and three new development wells were drilled and completed in our production licences at Poltava through the latter eight months of the year, and a successful appraisal well drilled in our Zaplavskoye exploration licence. These were followed by the first new well on the Elizavetovskoye field which was completed successfully in January of this year with a production rate significantly above expectations. This well is now tied-in to the new Elizavetovskoye production facilities which were completed on schedule and on budget at the end of the reporting period. In the third quarter of the period, the Company successfully completed a large 10-stage multi-frac of the 1-km horizontal section of well R-103 in the Rudenkovskoye field. Initial gas flow from the reservoir exceeded 6 MMcfd but levelled off at approximately 3 MMcfd, which was at the lower level of expectations.

In southern Russia, production from the Koshekhablskoye field reached nominal plant capacity of 40MMcfd, and we demonstrated that the plant is capable of operating above this level. A number of large acid treatments were employed on the production wells during the period and yielded excellent results. Regular smaller acidisations treatments are currently employed to maintain production levels. A fifth production well was worked-over, side-tracked and completed in the period bringing the total number of worked-over production wells on the field to five.

Work commenced in the period on the 170 sq. km Georgievskoye exploration licence which is contiguous with the Koshekhablskoye production licence. The existing 2D seismic data set was reprocessed and re-interpreted and a number of seismic anomalies identified.

Activity on the Company's non-operating interests in Hungary and Slovakia continued at a low level during the period. The Company has now withdrawn from its minority participation in the Provadia licence in Bulgaria.

Our organisation

The capability of the technical and construction departments of our Ukrainian subsidiary, PPC, was again demonstrated in 2013 with its concurrent organisation and supervision of the largest on-shore multi-frac operation to date in Europe, and the timely completion of design, fabrication, installation and start-up of our new production facilities in the Elizavetovskoye field. In addition, the company continues to provide technical assistance to its sister company, YGE, in southern Russia.

The capability and expertise of the personnel within our Russian subsidiary, YGE, continue to grow, particularly in the area of plant operation and optimisation. Also, the experience already gained in work-overs and downhole operations on HP/HT wells of more than 5,000m depth will clearly be of critical importance in the forthcoming tubing replacement operations.

Managing our risks

Risk is intrinsic to the oil and gas industry, particularly so in the areas of the world where we operate. We have committed to expending considerable resources and expertise in managing risk, and developing and employing the tools to aid our personnel to do so efficiently and effectively. During 2013, we strengthened our internal control and risk management processes and continued in our task of embedding these across all operations in the Group. Regular scheduled revision of our risk register and review of our procedures are essential features of this process, with continued oversight at Board level. Existing policies and procedures are followed to ensure we are complying with the UK Bribery Act and its guidance.

Outlook

We embarked last year on an exciting two-year development programme in Russia and Ukraine aimed at accelerating the growth of the Company with a rising level of Group production. A number of the milestones in the programme have been met in 2013, but several projects are still underway and scheduled to reach fruition in 2014.

In Ukraine, the immediate focus is accelerating the Elizavetovskoye development. The recent successful completion of our second production well has already brought our field production close to the 15 MMcfd nominal capacity of the plant; this is significantly fewer than the five wells planned, and at a concomitant lower cost and shorter time-frame. We now have the opportunity to bring forward the second phase of development of the field with drilling of the deeper sandstone reservoirs after mid-year. This will entail expansion of the production facilities but should lead to both increased Ukrainian production levels and reserve additions. Following the successful stimulation of well R-103, the next stage of development of the Rudenkovskoye field is the drilling of a vertical well in the fourth quarter of the year which will be stimulated by a 4-5 stage multistage frac focussing on zones analogous to the most productive zones in well R-103. In addition to the above, further development drilling will be undertaken in our production licences in Poltava, and the waterflood projects initiated on our mature fields.

In Russia, the priority for the current period is maintaining the maximum stabilised flow from our five production wells. In the short term, tubing replacement is required in wells 5 and 27, with the subsequent introduction of chrome-alloy, corrosion-resistant tubing identified as the long-term solution to the highly corrosive nature of our produced fluid. Expansion of the plant capacity to 60 MMcfd will be undertaken in stages over the period. A seismic acquisition programme is also planned for the adjacent Georgievskoye exploration licence in the latter part of the year.

Your Board, management and all employees are committed to growing the Company and its asset base going forward for the benefit of all shareholders. I thank all employees for their dedication to our common goals and our shareholders for their belief and support of the Company.

Dr Paul Davies

Chief Executive

FINANCIAL REVIEW 2013

In the first quarter of the period under review, the Company began a two-year investment programme to increase production volumes in Ukraine. Our drilling and appraisal programme restarted in April, following a six month interruption. Funding from the convertible bond was completed in February 2013 and enabled the Company to pursue its strategy to develop the Elizavetovskoye field, begin the appraisal drilling of its Zaplavskoye licence, complete its multi-frac on the Rudenkovskoye field and improve production from its Ukrainian mature fields through a waterflood programme.

These programmes are on track and, in conjunction with the plant expansion activities in Russia, are expected to result in increased production from both areas in 2014. In the meantime, production at, or at times in excess of, plant design capacity in Russia has dramatically improved the financial performance of our operations there and positively contributed to the Company's overall results.

Attractive commodity prices in Ukraine continued to support our operating profits and cash flow in 2013.

Revenue

Group revenues of $180.7m (2012: $202.9m) were down 10.9% from the prior year, due to a 21.0% reduction in revenues from Ukraine partially offset by a significant increase in revenues from Russia. The lower Ukrainian revenues were primarily the result of a 27.8% reduction in Ukrainian production volumes across all three products (oil, gas and LPG) caused by the interruption to drilling and appraisal work whilst we leased our rig and conserved cash in 2012 until we were able to identify and secure funding for our next investment campaign.

Group revenues in 2013 by region comprised: Ukraine $151.0m (2012: $191.1m), Russia $28.9m (2012: $5.1m) and Hungary $0.8m (2012: $6.6m).

Average sales volume rose 27.2% to 9,489 boepd (2012: 7,462 boepd), with 50.7% (4,815 boepd) sold in Ukraine, 48.9% (4,641 boepd) attributable to Russia and the remaining 0.3% (33 boepd) in Hungary.

The reduction in Ukrainian gas sales was the largest contributor to the fall in revenue, accounting for approximately 46%, followed by oil sales 33% and then LPG sales at 10%. Decreasing production in Hungary contributed a further 11%. The increase in Russian gas sales however offset 53% of this fall in revenue. The decline in gas and oil production volumes in our mature Ukrainian fields caused by our drilling interruption was the principle reason for this fall ahead of the early stages of our investment programme to improve production from our suite of fields in the Novo-Nikolaevskoye Complex and our new development in the Elizavetovskoye field. In Ukraine, the split of gas and oil production remains reasonably constant at 71%/29% (2012: 73%/27%).

Gas Sales

The significant increase in production and resulting sales volumes (415%) from our Russian field dominated our product mix in 2013 and meaningfully contributed to revenues.

Average gas realizations in Russia improved by 6.5% from $2.60/Mcf to $2.77/Mcf in 2013 whilst in Ukraine they dropped slightly by 1.3% from $12.12/Mcf to $11.96/Mcf. The combination of lower realisations on Russia sales and their meaningful contribution to Group sales resulted in an overall average reduction of 36.2% to $6.73/Mcf (2012: $10.55/Mcf).

Oil Sales

Reduction in oil sales was driven by a 22% decline in volumes rather than price as international oil prices held relatively firm. Average oil realizations were 1.5% less at $92.12/bbl (2012: $93.55/bbl) in line with trends in international oil prices.

LPG Sales

As gas sales volumes in Ukraine decreased by 17%, LPG sales were affected by both volume declines associated with a reduced volume of gas produced, and a drop in the market price achievable in Ukraine. The average price realised was $897.71/tonne (2012: $970.59/tonne). However, the strong operational performance of the Ukrainian LPG plant enabled it to contribute $13.9m (2012: $18.5m) to Group revenue.

The total Group sales volume gain of 35.1% was largely a result of Russian sales; however, it was accompanied by a decrease in the Group average gas price realized because the Russian sales volumes currently attract considerably lower realisations than the Ukrainian volumes.  

REALISATIONS

Profit from operations

Profit from operations of $9.2m (2012: $51.6m before exceptional charges of $45.8m) resulted from the decrease in revenues of $22.2m to $180.7m (2012: $202.9m) and an increase in total cost of sales.

Total cost of sales for the period increased by $18.2m to $147.3m (2012: $129.1m excluding exceptional charges of $45.8m) mainly due to increases in:

· Russian operating costs of $12.0m

· Ukrainian oil and gas inventory movements and product purchases of $11.8m

· DD&A charge of $3.4m

which were offset by reductions in production based taxes of $5.6m and a write-off of exploration and evaluation costs of $3.4m. The Russian operating cost increase of $12.0m is entirely due to the inclusion of a full period of operating costs from our Russian Gas Processing Facility ('GPF'). Commercial production commenced in April 2012 and therefore the previous (2012) period does not include a full year charge. In addition, due to a full year of operations, an incremental $2.9 million of administrative costs were incurred, offset by a reduction in foreign exchange losses of $0.9 million. Ukrainian sales from inventory and product purchases during the period caused an additional $11.8m charge (2012: $2.3m gain) as we maintained our sales levels despite reduced production during certain periods. Taken together, the increase of $23.8m in operating costs resulted in a 56% rise (on a boe basis) in production costs to $13.71/boe from the $8.79/boe experienced in 2012.

Production based taxes for the Group reduced by 11.8% or $5.6m to $41.8m (2012: $47.4m) mainly as a result of lower gas and oil production volumes in Ukraine in addition to a small reduction in the oil tax charge (from $37.70/bbl to $36.69/bbl), which was partially offset by increases in gas production tax charges in both Ukraine and Russia. The Group's effective gas production tax charge dropped (from $63.01/Mcm to $46.51/Mcm) as a result of the substantial contribution of Russia gas to the production mix which is taxed at a much lower rate than gas produced in Ukraine. Average gas tax charges in Russia increased from $8.0/Mcm to $10.9/Mcm in 2013 and average gas tax charges in Ukraine increased from $73.3/Mcm to $99.6/Mcm.

This reduction is reflected in production tax on a boe basis dropping to $11.77/boe (2012: $16.70/boe).

Exploration and evaluation costs written off were $3.4 million less at $1.5m (2012: $4.9m) due to the reduction in exploration activity and drilling during the year.

The Group's administrative expenses increased to $24.1m (2012: $21.2m), mainly due to inclusion of a full year charge of expenses in Russia after commercial production commenced in April 2012.  

Profit for the year

Profit after tax was $6.5m (2012: loss $11.3m after an exceptional charge of $36.0m (net of tax)). This is a 158% improvement over 2012 due to the absence of exceptional items in 2013. On a pre-exceptional basis, profit declined to $6.5m from $24.7m in 2012.

On a pre-exceptional basis, the $18.2m reduction is the combined result of:

· an $22.2m decrease in revenues mainly due to reduced Ukrainian oil and gas production

· an increase in operating charges of $18.2m to $147.3m (2012: $129.1m) as a result of a full period of Russia operating costs, Ukrainian charges related to sales from inventory and gas purchases and increased depreciation, depletion and amortisation ('DD&A'), offset by a decrease in Ukrainian production taxes from lower volumes and rates and a reduction in the write off of exploration and evaluation costs

· a net increase in administrative, foreign exchange and net finance charges of $1.0m

· a $2.0m fair value loss on the derivative attached to the convertible bond

· a $25.2m reduction in the taxation charge, excluding the tax effects on the exceptional items.

Basic earnings per share after exceptional items were much improved at 3.78 cents (2012: loss per share of 6.59 cents).

Finance costs

Finance costs have reduced by 23.7% to $3.6m (2012:$4.8m) as a result of the lower level of the convertible bond interest in comparison with both the Credit Suisse interest charge on the prepaid swap and Credit Agricole working capital facility interest charges experienced in 2012. The $2.0m charge for the fair value movement on the derivative liability represents the change in fair value of the conversion option associated with the convertible bond since its completion on 19 February 2013. The bonds have a conversion option which becomes more valuable to the bond holder as the Company's share price nears or exceeds the fixed conversion strike price (76.29 pence). As the Company's share price has increased from 64.75 pence at Bond completion on 19 February to 71.50 pence at year end, a charge has been recognised that represents the increase in fair value of the potential liability of the Company to settle any conversion options that may be exercised in future periods.

Earnings per share

Basic earnings per share after exceptional items of 3.78 cents were a significant improvement to the previous year (2012: 6.59 cents loss). As there were no exceptional items in the reporting period, basic earnings per share before exceptional items were also 3.77 cents (2012:14.36 cents).

Taxation

The total tax credit for the year was $2.5m (2012: charge $13.0m), comprising a current tax charge of $8.6m (2012: $18.9m) and a deferred tax credit of $11.1m reflecting recognition of the Russian deferred tax asset (2012: net credit $5.9m, after a deferred tax charge of $3.9m and an exceptional deferred tax credit of $9.8m).

The fall in current tax charge of $10.3m reflects a combination of lower profitability in addition to a reduced rate of corporation tax applicable in Ukraine.

In December 2010 a new Ukrainian corporation tax rate was introduced which set the 2012 corporate tax rate at 21% and 2013 rate at 19%. In 2014 the corporate tax rate has reduced to 18%.

Other taxation - general

The production based tax expense for the year was $41.8m (2012: $47.4m) representing an 11.7% reduction which has been recognised in cost of sales.

Other taxation - Ukraine

The royalties and rental costs regime in Ukraine changed to a single production tax system for oil and gas from 1 January 2013 making our position and future liability simpler and more predictable. The rates are subject to minimum thresholds.

At the prevailing production and border price levels for 2013, the average production tax charge on gas was $99.6/Mcm (2012: $73.3/Mcm) and $36.69/bbl (2012:$37.70/bbl) on oil.

Other taxation - Russia

In September 2013 the government approved a new gas and condensate mineral extraction tax ('MET') formula (to be implemented from 1 July 2014) after much debate and speculation on the subject. The new formula is based on gas prices, gas production as a share of total hydrocarbon output and complexity of gas reservoirs (depletion rates, depth of the producing horizons and geographical location of producing fields). The MET applicable in 2013 was 389 Roubles/Mcm (2012: 334 Roubles/Mcm). The rate applicable from 1 July 2014 will be approximately 290 Roubles/Mcm, which is less than the maximum applicable rate (580 Roubles/Mcm) due to the depth of the producing horizons at our Russian field which is a 50% saving. The current legislation provides for a further increase in the maximum rate to approximately 660 Roubles/Mcm on 1 July 2015 with the resultant applicable MET for our production of 330 Roubles/Mcm.

In addition to production taxes, we are subject to a 2.2% property tax which is based on the net book value of our Russian assets calculated for property tax purposes. This amounted to $3.7m in 2013 (2012:$2.5m). The figure is included in other cost of sales in the consolidated income statement.

Operating cash flow

Pursuant to a year with significant resources spent on new drilling and workover projects to ensure future production levels are maintained, the Group generated cash from operations of $74.8m (2012: $109.3m). This was 31.6% lower mainly due to lower production and sales in Ukraine.

Interest and bond charges paid were $6.7m lower at $2.2m (2012: $8.9m) mainly because the prepaid swap facility matured in 2012.

Corporation tax paid was 27% lower at $15.9m (2012: $21.8m), predominantly due to the reduction in corporation tax rates in Ukraine in 2013 and lower profitability.

Net cash generated from operating activities was $21.8m lower at $56.7m (2012: $78.5m) as a result of the $34.5m reduction in net cash from operations, offset by a $6.7m decrease in interest payments and a reduction of $5.9m in corporation tax payments.

Cash flows from investing activities

Capital Expenditure - Property, Plant and Equipment

Our investment in property plant and equipment in 2013 was $5.2m lower than the prior year at $61.5m (2011: $66.7m).

Investment in our Russian plant and equipment accounted for $20.2m (2012: $40.6m) of the Group's capital spend in the year, representing 31.4% (2012: 60.3%) of the total for the year. The 2013 cost mainly relates to workover activity and acidisation of wells throughout the year to bring the performance of the wells up to full production capacity.

At the end of the year, the carrying value of the Group's oil and gas assets in Russia was $286.3m (2012: $299.6m). The value of this investment in comparison with the carrying value of the Group's Ukrainian oil and gas assets ($169.1m) demonstrates the importance and size of this operation to the Group. The focus of the ongoing and future work is to increase the plant capacity by a minimum of 50% to 60 MMcfd and have a suite of producing wells which fill this capacity in addition to providing a level of redundancy during periods of well intervention.

Capital expenditure in Ukraine during 2013 was $41.7m (2012: $22.8m). Our Ukrainian capital investments included completion of our successful frac on wellR-103 and the drilling of the first Elizavetovskoye well E301, as well as appraisal and workover wells on the mature fields using the Skytop N-75 and TW-100 rigs. 2013 also saw capital expenditure relating to completion of the Elizavetovskoye processing facilities and the installation of the LPG plant upgrade. These projects all comprise part of the investment programme outlined at the beginning of 2013 to increase production from our existing production licences and exciting new appraisal opportunities.

Exploration expenditure

Exploration expenditure fell to $0.4m (2012: $3.8m) in 2013 with no expenditure (2012: $2.6m) in Ukraine, $0.2m (2012: $0.7m) in Hungary and $0.2m (2012: $0.5m) in Slovakia. The overall reduction of $3.4m is dominated by the absence of exploration drilling in Ukraine but also reflects our reduced focus on our Hungarian exploration prospects following some disappointing drilling results in 2011 and 2012. Additionally, delays were experienced in the development of our Slovakian interests due to the operator's organisational changes.

The review of asset carrying values in the statement of financial position concluded that no impairments were required.

Cash flow from financing activities

Net cash inflow from financing activities in the year improved dramatically to $19.2m (2012: outflow $15.9m) comprising $37.8m of cash inflow from bond proceeds and $0.4m of restricted cash, off-set by a $15.0m repayment of the working capital facility provided by Credit Agricole and $4m for the purchase of employee trust shares. The 2013 improvement reflects the combination of our fundraising activity and the repayment of $40 million due on the Credit Suisse prepaid swap in 2012.

Financial instruments

The Group employs a number of financial instruments to manage the liquidity associated with the Group's operations. These include cash and cash equivalents, together with receivables and payables that arise directly from our operations.

Separate from these, the main financial instrument of the Group is the $40 million guaranteed unsubordinated convertible bond which was placed in Q1 2013 with institutional investors and is due in 2018. The bonds have an annual coupon of 8 per cent per annum payable semi-annually in arrears. The bonds terms and conditions contain an annual put option each February until maturity. None of the bondholders exercised the option to put 10% of the outstanding principal of the bonds in February 2014. Further information on the terms and conditions of the bonds is included in notes 12 and 13.

The Group renewed the Credit Agricole working capital facility in Q2 2013 and continues to benefit from the flexibility that this financing provides our Ukrainian subsidiary, in particular to manage its working capital needs. The facility is available until 30 June 2014 with the maximum facility reducing to $10.0m and $5.0m on 30 April 2014 and 30 May 2014 respectively. There were no drawings outstanding on 31 December 2013.

Cash

Cash at the end of the year (excluding restricted cash) was $25.7m (2012: $12.0m). This resulted from a cash balance at the beginning of the year of $12.0m (2012: $19.1m) enhanced by an increase in cash and cash equivalents during the year of $14.3m (2012: $7.4m decrease), before the effects of foreign exchange on cash balances of $0.6m (2012: $0.3m).

Total cash resources and undrawn bank facilities at the end of the year were a healthy $40.9m including the unused Credit Agricole facility and restricted cash (2012: $12.7m).

Dividends

No dividends have been paid or proposed during the year and the Board will not be recommending the payment of a dividend at the forthcoming AGM.

Liquidity

Following the settlement of our short-term borrowings during 2012, the completion of the 5-year convertible bond placing in February 2013 (see note 12 to the financial information) and the cash requirements of our Russian project reducing, the Group's liquidity position has strengthened markedly.

Our immediate priority is to complete the investment programme outlined in 1Q 2013 at the time of placement of the convertible bond. This is a two-year programme and we have successfully completed a number of important activities in 2013 which were integral to the goals of production increases of both oil and gas in our areas of operation.

The Group has the ability to fund its future operating and capital expenditures through existing working capital, cash flow from operations, and the bond proceeds. Our low level of gearing and the Credit Agricole facility together provide us with the financial flexibility to support our operating and growth objectives.

Outlook

In Ukraine, we expect gas prices to increase. The recent breakdown in relations between Russia and Ukraine has resulted in the revocation of the discount granted to Ukraine from $400.0/Mcm to $268.5/Mcm in its 10 year gas Supply Agreement with Russia which it entered into in January 2009. This discount was in the form of a "y" coefficient which would be applied on a quarterly basis to the calculation of the border price of gas pursuant to the Supply Agreement. The coefficient was offered as part of a rescue package Russia agreed with Ukraine in Q4 2013 as an alternative to the pursuit of formal arrangements with the EU.

Subsequent events have overtaken this arrangement. Russia does not recognize the interim government in Kiev as legitimate and therefore has revoked this discount. Gazprom has announced that the "y" coefficient which was to apply to gas sales from 1 April 2014 for Q2 2014 will not apply. As a consequence, the border price, which has a direct impact on the industrial tariff that applies to our Ukrainian gas sales, is expected to increase. Ukrainian authorities estimate the border price for Q2 at $368.5/Mcm. It is noteworthy that, despite an approximate 33% decline in the border price during the first quarter of 2014, the National Regulator for Electricity and Gas ('NKRE') chose not to reduce the industrial price commensurate with the reduction in the border price and implemented a reduction of only 11%. The unprecedented approximate 25% devaluation of the Hryvnia US Dollar exchange rate during the quarter resulted in lower short term industrial prices expressed in US Dollars. NKRE has announced that they will quote a new industrial price on a monthly basis beginning in April to adjust for both import tariff and foreign exchange movements.

Furthermore, there is speculation that Russia may no longer comply with the terms of an earlier (April 2010) amendment to the Supply Agreement as a result of its planned absorption of Crimea into the Russian Federation. This agreement offered specific discount terms in exchange for the prolongation of the lease on the Russian Black Sea fleet's base in Sevastopol, Crimea. Currently, this results in a flat $100/Mcm discount to the contract terms contained in the Supply Agreement. Consequently, it is possible that the current gas price at the border may increase by a further $100/Mcm.

Given the current geopolitical circumstances between Russia and the Ukraine, we do not expect to see a reduction in the contractual price pursuant to the Supply Agreement in the near future. Reductions are only expected to occur as a result of any reduction in the basket of oil based products on which this Supply Agreement is based.

We anticipate our oil realisations to remain firm and the reduction in oil production tax, which took effect in 2013, to continue through the current period. 

In line with Russian legislation, the regulated wholesale industrial gas price in Adygea is scheduled to increase annually at 15% through 2015 from their year-end prices of 4,228 Roubles/Mcm. In the third and fourth quarters of 2013 following guidance from the Ministry of Economics, there was much speculation that an increase in 2014 would be either eliminated entirely or reduced to inflation. Despite high market expectations of legislative change in this regard, we have not seen any official position contrary to the current legislation and the discussion in the industry press on this topic is almost non-existent. However, we have reduced our expectation with respect to the gas price increase due to be effected 1 July 2014.

We have benefited from the revamping of the Russian production tax regime in 2013 where an allowance for deep wells such as ours has resulted in a reduction in tax on our production from the Koshekhablskoye field. We continue working to maintain sustainable high rates of production from our suite of wells in order to deliver maximum throughput for the expansion planned on the gas processing facility from 40MMcfd to 60MMcfd.

We remain confident that Ukrainian production will continue to rise as a result of our investment programme. The higher than expected flow rates from the first Elizavetovskoye well are encouraging and we look forward to accelerating our programme on this field to realise its maximum potential as soon as possible. The results from the successful large multi-frac on the Rudenkovskoye field have enabled us to plan another well for this development, with the benefit of the significant data gathered allowing us to reduce capital cost going forward. Our waterflood programme on our mature fields and our exploration and appraisal programme in the Zaplavskoye licence, are progressing smoothly. The waterflood programme's objective is to enhance our recovery of the remaining oil in our Ignatovskoye and Molchanovskoye fields. The Zaplavskoye activity aims to continue our proven track record of identifying and extending production from areas in which we have deep knowledge.

We are fully funded for our planned capital investment programme for the next two years and to maintain a healthy liquidity position due to the remaining proceeds of the bond placement alongside improved internally generated cash flow. We anticipate our low level of gearing to continue as our options for debt financing are limited by our Ukrainian focus and our current shareholder base.  

OPERATIONS REVIEW - UKRAINE

2013 update

Our key achievements in Ukraine during the year were:

· Completion of Elizavetovskoye production facilities on schedule by year end.

· Drilling and completion of the E-301 well and bringing it on-stream early in 2014 at over 6 MMcfd - more than twice the expected rate.

· Successful execution of the 10-stage multi-frac of well R-103 in the Rudenkovskoye field.

· Upgrade of the LPG plant at the Novo-Nikolaevskoye Complex to enhance propane recovery with increase in the overall LPG yield by 25%.

· Encouraging results from the newly acquired West NovoNikolaevskoye 3D seismic data with a number of leads and prospects being assessed for drilling in 2015.

· Introduction of an aggressive production maintenance programme to combat build-up of wax and scale in the wells, well-heads and flowlines.

Ukrainian Reserves

The most significant addition to Ukrainian reserves has been in the Elizavetovskoye field where 2P reserves have increased from 3.7 MMboe to 6.9 MMboe with start-up of production. There have also been small increases in the other production licences (except Rudenkovskoye) with total 2P reserves in Ukraine at the end of 2013 increasing from 29.4 MMboe to 33.1 MMboe after production of 1.7 MMboe in the year.

Novo-Nikolaevskoye Complex production facilities

2013 update

Liquefied Petroleum Gas ('LPG') Production Facilities

The LPG processing, storage and delivery system has proved to be a valuable add-on to the existing plant at theCentral Production Facility. In 2013, the plant was modified to enhance the recovery of propane with results exceeding expectations. Yield increased from approximately 1.89 tonnes/MMcf of gas produced to approximately 2.40 tonnes/MMcf - a 27% improvement overall.

Average LPG sales through 2013 were 42 tonnes per day (2012: 52 tonnes per day).

Other gas production facilities

No other significant upgrades took place in 2013 nor are any planned for 2014. Work continues on plant and gas lift optimisation, re-routing flowlines to reduce back pressure, and wax clearance to enhance production from the available well stock. Production maintenance is now a critical part of the daily operation, particularly in the winter months. The combination of wax cutting, flowline pigging and hot-oiling and, most recently, the introduction of compounds to clear salt build-up in both the tubing and the well-heads have had a significant effect in maintaining production levels in mature fields.

2013 update

During 2013 two new wells were drilled and three wells worked over on the Ignatovskoye field:

· appraisal well IG-132 targeted the Tournaisian carbonate reservoir in the northern part of the Molchanovskoye field but within the Ignatovskoye licence area. The well, which was drilled to a total depth of 2,759 metres, encountered a 300 metre section of gas bearing limestone and dolomite reservoir of which around 60 metres was considered to be of reservoir quality. Following an open-hole completion over the carbonate and a 30 cubic metre acid squeeze, the well flowed at an average rate of 1.35 MMcfd and 28 bpd of condensate.

· well IG-107 well was drilled to appraise the Visean and Tournaisian carbonate reservoirs and the Devonian sandstone in a downthrown fault block on the east flank of the Ignatovskoye field. Despite evidence of hydrocarbons on the logs and an acid squeeze, the carbonate reservoir proved to be tight and production was minimal. The well was subsequently re-completed to the Devonian sandstone where, again, the logs indicated the presence of hydrocarbons but, again, production was minimal. The well continues to produce with regular shut-ins for pressure build up.

· well IG-105 has been a Devonian sandstone oil producer for many years utilising a rod pump. The TW-100 workover rig successfully re-completed the well as a T2 sandstone producer of 40 bopd with gas lift.

· the workover rig recompleted wells IG-110 and IG-127 as Triassic water production wells. These recompletions were the first steps in the Ignatovskoye carbonate waterflood scheme. Testing confirmed that there was an adequate water supply, and fluid compatibility tests indicated that some additives would be required to minimise scale build-up.

Outlook

Two appraisal wells are under consideration for 2014. These include a Devonian test on the north flank of the Ignatovskoye structure and a possible northern extension of the western flank play. Targets have been finalised and site preparation is in progress.

Reservoir simulation has played an essential part of the preparation for the Ignatovskoye waterflood programme and these results are being combined with the engineering study for submission as a development plan by mid-2014. The Ignatovskoye water-flooding project is now focussing on the oil bearing south flank of the field where a modest increase in ultimate oil recovery is anticipated.

Ignatovskoye reserves

The 1.19 MMboe addition to 2P reserves derived from reservoir modelling exceeded 2013 production of 1.00 MMboe from the field. The year-end remaining Ignatovskoye reserves have consequently been revised upwards to 11.72 Bcf of gas and 1.43 MMbbl (total 3.39 MMboe).

Molchanovskoye production licence

2013 update

During 2013 one new well was drilled and two wells worked over on the Molchanovskoye fields.

Molchanovskoye North

Work in the Molchanovskoye North reservoirs in 2013 continued to focus on optimising oil recovery from the Devonian sandstone ahead of preparations for the proposed waterflood.

· Well M-166X was drilled by the N-75 rig as the second sidetrack of the M-166 well in the productive Devonian sandstone reservoir. The well was drilled to a total depth of 2,941m and penetrated 207m of reservoir along its planned horizontal trajectory at 2,650m true vertical depth subsea. It was completed with 100m of pre-perforated liner below 107m of blank pipe leaving room for further recompletion towards the end of the well's life. The initial 12 hour flow rate stabilised at an average of 1,710 bopd with 2.1 MMcfd gas. After further testing, production was set at a lower choke size to manage the reservoir and prevent early water breakthrough. This was managed successfully through 2013, but oil production has now fallen as the water cut has increased to 90%. However, the well continues to produce on gas lift.

· A further recompletion of well M-171 and the use of chemical cleaners of the well bore and flowline resulted in a production increase from 10 bopd to 50 bopd.

· Workover of well M-154 was the final perforation of the Devonian sandstone right at the top of the oil leg. Oil was produced with a water cut was over 95%. Well M-154 is currently shut-in as a potential candidate as a water injector for the waterflood programme.

Outlook

No further drilling is planned for 2014 and work will now focus on developing the waterflood programme. Seismic interpretation is complete and, with reservoir modelling progressing, these results will be combined with the engineering study for submission as a development plan in the second half of 2014.

Molchanovskoye Wedge Zone

This zone is approximately 400m deeper than any gas or oil found to date in the adjacent Molchanovskoye fields. There are two wells on the discovery: the successful M-170 well and the nearby dry M-172 well.

Additional zones have been perforated in well M-170 which gave significant, but short, bursts of incremental production. However, the well does continue to produce at modest rates.

Outlook

No further drilling is planned for 2014 and, following re-interpretation of the seismic, work continues on understanding the relative geological settings of the wells before committing to a third well in the area.

Molchanovskoye Main reservoirs

Production from the Molchanovskoye Main field wells continued to fall through 2013. All the wells are depleted and have now been shut-in and, with the exception of well M-202, abandoned.

Molchanovskoye reserves

The 0.36 MMboe addition to 2P reserves derived from reservoir modelling was essentially equal to the 2013 production from the Molchanovskoye fields of 0.35 MMboe. The year-end remaining Molchanovskoye reserves are consequently unchanged at 3.2 Bcf of gas and 0.2 MMbbl (total 0.7 MMboe).

Currently no reserves have been recognised for the Wedge Zone.

Novo-Nikolaevskoye production licence

2013 update

During 2013, work on the Novo-Nikolaevskoye licence comprised one workover and incorporation of the newly acquired West NovoNik 3D seismic set into the overall seismic interpretation.

· The TW-100 workover rig was used to recomplete well NN-71 from the V-16 to the V-15 reservoir and, following incorporation of gas lift, the well flowed at an initial rate of 5.4 MMcfd with 264 bopd.

· The seismic data have been re-processed and re-interpreted. Amplitude analysis has indicated a strong anomaly consistent with well NN-71 and the long-lived well NN-09. This evaluation also goes some way to explaining the disappointing results from the 2012 Novo-Nikolaevskoye drilling programme.

Outlook

Combining seismic interpretation with updated reservoir modelling indicates the potential for incremental reserves in the V-15 reservoir which should be recoverable through additional drilling. Well NN-80 will be drilled in the second quarter of 2014 and, depending on well results, may lead to further drilling in the licence.

Novo-Nikolaevskoye reserves

The 0.5 MMboe addition to 2P reserves exceeded 2013 production of 0.2 MMboe from the field. The year-end remaining Novo-Nikolaevskoye reserves have consequently been revised upwards to 2.7 Bcf of gas and 0.1 MMbbl (total 0.5 MMboe).

The Rudenkovskoye production licence

2013 update

R-103 Multi-stage Frac

The 10-stage multi-frac was successfully completed in early September. This was one more stage than originally planned to compensate for a poor frac early in the operation. In total, 670 tons of proppant were injected along with 34,000 barrels of frac fluid. Maximum frac reach was over 240 metres and the propped width ranged from 3 to 6 millimetres. Initial gas flow from the reservoir exceeded 6 MMcfd but this has since levelled off at approximately 2 MMcfd by the end of the year.

The well is still producing around 5-15 bpd water; however, water analysis suggests that this is now water of condensation and that the well has finally cleaned up. Over 15,000 barrels of frac fluid have been recovered to date which is more than 45% of the total injected - much higher than expected.

Installation of a smaller diameter velocity string within the production tubing has just been completed. This should aid fluid recovery and minimise the risk of liquid loading thereby freeing up gas production, particularly in the lower frac zones.

Outlook

The stabilised production rates following the multistage frac of well R-103 are at the lower end of expectations and have prompted a reconsideration of the on-going appraisal programme:

· re-interpretation of the 2012 reprocessed seismic data has added little to our understanding of the internal structure of the reservoir and a limited area, high resolution 3D survey is now planned for later in 2014. Also underway is a comprehensive chemostratigraphic analysis of the Devonian reservoir in the Rudenkovskoye wells to help in dating and correlation between wells. (If successful, this technique may be applied to the Molchanovskoye Wedge Zone wells to aid interpretation there.)

· the flow rates achieved to date in well R-103 do not justify the cost of drilling a 1,000m horizontal section and then carrying out a 10-stage frac. Well R-105 is therefore being planned as a vertical well through the 300m thick Devonian reservoir section for drilling in the fourth quarter of 2014. This will be followed by a 4-5 stage multistage frac focussing on zones analogous to the most productive zones in well R-103.

Rudenkovskoye reserves

Production and remodelling has led to a small reduction of 0.17 MMboe in the reserves in the Rudenkovskoye field to 121.2 Bcf of gas and 1.2 MMbbl of condensate (total 21.4 MMboe). Further reassessment will follow the 2014 appraisal programme.

Zaplavskoye exploration licence

2013 update

Work was completed on the interpretation of the new 3D seismic data over the West Novo-Nikolaevskoye area of the Zaplavskoye exploration licence. The interpretation focused on understanding the potential for further gas accumulations in the Visean V25 and V26 wet gas reservoirs discovered in the Z-04 exploration well. It would appear that the trapping mechanism is provided by a combination of structural and stratigraphic features. A similar trap has been mapped to the east of the Molchanovskoye Main field and some larger, but deeper, Devonian structural leads have also been identified.

The appraisal well Z-05 was drilled in the second half of the year to test the Visean sandstone reservoirs. It was deviated to a bottom hole target some 500m southeast of the discovery well Z-04 but found only poorly developed V25 and V26 reservoirs - effectively the pinchout. The well was side-tracked to a location further to the north where it encountered around 8m of V26 reservoir and 1m of V25 reservoir. Initial flow rates were spectacular but, as with well Z-04, decline was rapid. The well continues to produce with regular shut-ins for pressure build up.

Outlook

Geological assessment of the seismic interpretation along with amplitude analysis of the data have opened up a number of leads and prospects in the West Novo-Nikolaevskoye area which are now being evaluated as possible drilling targets, although with the current full drilling programme for the SkyTop rig, the earliest slot appears to be in the first half of 2015. The economics of contracting a second rig is under consideration.

Elizavetovskoye exploration licence

2013 update

The Elizavetovskoye EPF is a simple water knock-out facility and has been designed with a nominal throughput capacity of 15 MMcfd to accommodate the carbonate reservoir development. Gas is exported via an 11 km, 6-inch pipeline which was connected by a hot-tap to the Ukrainian gas transportation network in 2011.

· Well E-301 was drilled to a measured depth of 3,102m (2,865m TVD) and is now in production from the primary Permian A2 carbonate reservoir. Production has settled above 6 MMcfd with 10-15 bpd condensate.

· Good progress is being made on the 145 sq. km. 3D seismic survey currently being acquired over the Elizavetovskoye area with completion (due by) the end of February.

· The legacy well, East Machevska-53 (EM-53), was brought into production in 2013, and continues to flow at around 2.0 MMcfd (gross) with 7 bpd condensate.

· PPC is contributing to the upgrading the separation and metering facilities at the Ukrgasvydobuvannya's East Machevska gathering point as part of the JPA.

· Well E-302 is also complete and in production. It tested at a rate of 6.2 MMcfd with 14 bpd condensate through a 44/64" choke at a flowing wellhead pressure of 760 psi.

Outlook

The success of well E-301 led to a rescheduling of the 2014 development programme. The E-302 development well has now been completed in the A2 carbonate reservoir in the same manner as well E-301 while well E-304, to be drilled in the third quarter of 2014, will appraise the deeper G sands reservoir. All the early wells are being located on the basis of existing legacy well data. The significant improvement in production from wells E-301 and E-302 compared to the legacy well EM-53 reflects the modern standards of drilling, completion and stimulation of the reservoir section being achieved by our Ukrainian subsidiary, PPC.

Completion of interpretation of the 3D seismic and the core data from well E-301 will provide a better understanding of the distribution of both the A2 carbonate and the G sand reservoirs to aid the placement of further wells.

Re-evaluation of the EPF is now underway to accommodate the potential from both the A2 carbonate and the G sands reservoirs; compression will be brought forward and the metering system will have to be upgraded. In addition, new specifications for the hydrocarbon dewpoint level in the export gas have just been introduced and this will require additional plant modification.

Work is also in progress to convert the existing exploration licence into a 20 year production licence later this year.

Elizavetovskoye reserves

The 2P reserves for the A2 carbonate in the Elizavetovskoye field have been upgraded to 24.8 Bcf with 0.1 MMbbl of condensate (total 4.2 MMboe) and a further 15 Bcf with 0.05 MMbbl condensate (total 2.6 MMboe) have been added for the G sands, bringing the total Elizavetovskoye 2P reserves to 6.9 MMboe. Further resources have been identified and may be added to the reserves once the first wells have been drilled, the seismic interpreted and the early production data analysed.

OPERATIONS REVIEW - RUSSIA

2013 update

Koshekhablskoye Gas Processing Facility

The Koshekhablskoye gas processing facility ('GPF') began commercial production in April 2012.

Upstream issues have constrained production during the year although, as problems have been resolved, production has increased and at its peak reached 54 MMcfd - over 40% more than the plant design capacity.

Simulation modelling of the GPF based on actual gas composition and plant operating conditions has indicated that a revised plant design capacity of 60 MMcfd can be achieved with limited modifications. This will entail changes to some of the vessels, replacement of some valves and pipework and improvements to the operating procedures. The revised plan is being prepared for approval by the Russian authorities and it is hoped that this approval can be obtained in time to permit implementation during a brief plant shut down in late 2014.

A number of minor problems, such as amine foaming, have been encountered in the plant as delivery gas rates exceed 50 MMcfd, but the modifications required to address these issues are not subject to regulatory approval and YGE plans to implement these in the second quarter of 2014.

Sulphur emissions continue to be monitored closely and, at present, are within regulatory requirements. Nevertheless, as production increases, a sulphur recovery process may need to be considered to reduce the level of emissions. All relevant parameters and data are under continuous review.

Koshekhablskoye Production Well Activity

Significant progress has been made in bringing the existing production wells up to the expected production rates; however, all wells have required some form of intervention and some of these have proved to be both technically complex and time consuming operations.

Well workovers at between 5,000 to 5,750m (16,500-19,000ft) in wells which were drilled more than 20 years ago has proved to be challenging and expensive, although still significantly cheaper than drilling new wells to these depths. The small hole size of 4½", bottom-hole temperatures in excess of 170oC and bottom-hole pressures of around 8,000psi have all added to the complexity of any downhole intervention, particularly with a limited choice of materials and equipment capable of working reliably in these conditions. In particular, materials able to handle the sour gas conditions (H2S, CO2) has proved a particular metallurgical challenge and some of the tubing available in Russia has proved to be below standard. The Geostream rig, which has been working on the field since 2010, has now been released and alternative equipment is being sourced.

The well status is as follow:

· Crestal well-20 has proved to be the most productive well in the field. However, the well suffers from a build-up downhole of loose formation of mostly calcareous clay which progressively limits production rates. Repeated acid stimulation by a simple acid bull-heading operation using a local pump truck is required to clear the build-up. Production returns to 18 to 20 MMcfd following treatment, but this does require regularly application, typically every 4 to 6 weeks.

· Well-25 lies on the north flank of the field with the reservoir at around 5,500m. This well has proved to be a reliable producer. During the period, a routine acid bull-heading operation dislodged a piece of formation which required coiled tubing intervention to clear. The well is currently flowing at around 13 MMcfd.

· Well-15 lies deep on the east flank of the field with a reservoir depth of 5,750m in a less fractured area of the field. Following sidetracking and acid stimulation, the well finally flowed at up to 5 MMcfd. However, the well has proved susceptible to liquid loading and, despite a second acid treatment, the flow rate remains in the range 1.3-2.5 MMcfd, and requires regular short shut-ins for pressure build-up to lift the entrained liquids.

· Well-05 re-entry, sidetrack and completion was completed successfully in the fourth quarter of 2013 and placed on production ahead of acid stimulation at a rate of 2.5 MMcfd. However, drifting of the tubing indicated an obstacle at around 2,600m which appears to be a piece of damaged tubing. The well has been suspended and the tubing will be replaced as soon as a rig can be mobilised. Well-27 was the first well to be recompleted by YGE with a relatively straightforward workover and tubing replacement. The well has demonstrated that it is capable of producing at over 20 MMcfd, but more recently has been performing at 15-17 MMcfd. In the fourth quarter of 2013, a leak was detected in the tubing and, as pressure built up in the annulus, it was decided to pull and replace the completion. The operation was completed successfully at the end of 2013. In early February 2014, the pressure in well-27 again began to build in the annulus and there appeared to be communication with the casing annuli. The well is currently diverted to the flare pit and a coiled tubing unit is being mobilised to kill the well, prior to a complete tubing replacement and restoration of the pressure integrity of the well.

Outlook

YGE now has enough worked-over wells in the field to deliver 55-65 MMcfd to the gas processing plant. Considerable effort has gone into re-designing the completion and the re-specifying the materials in order that a sufficient number of wells are producing consistently at high delivery rates.

Orders have now been placed for chrome-alloy, corrosion-resistant tubing with premium connections, and the first two of these strings are due for delivery in the third quarter of 2014. The upper completion has been redesigned to minimise potential obstructions and ease the flow of gas up the well and equipment down the well. The lower completion is also being re-specified in order to minimise the inflow of formation materials whilst ensuring that gas flow and formation treatment can be maintained.

The replacement operation is expected to commence in the fourth quarter of 2014.

In the short term, wells 5 and 27 will need tubing replacement. As soon as a rig can be mobilised, it will start work on well-05. Work on well-27 will depend on the outcome of the kill operation and the subsequent evaluation of the well casing condition.

Work is also continuing on upgrading the flowlines from the wells to the plant. The original specifications were based on modest flows from the wells in the early phase of production. The much higher rates now being achieved by the wells have meant twinning pipelines and YGE is now evaluating the benefits of laying new, larger lines.

Koshekhablskoye Field Exploration and Appraisal

The production licence in Koshekhablskoye requires the drilling or workover of a well to the deeper Callovian reservoir and a reserves determination. YGE has continued to maintain a regular dialogue with Rosnedra, the licensing authority, and has recently reached agreement to defer completion of this licence commitment until June 2019. The obligation now entails re-entering and sidetracking well-09 to re-drill the full Callovian reservoir sequence and, if successful, testing of the Callovian V unit.

Koshekhablskoye Reserves

In compliance with licence requirements, the Oxfordian reserves will be reassessed later this year once all the wells are producing steadily. Callovian reserves are dependent on the results from well-09 and, when available, the data will be incorporated into the reserves assessment due in 2019.

Production from the Koshekhablskoye field in 2013 was 1.85 MMboe, but due to changes in the gas price forecast there has had to be a downward revision in the reserves by 1.3 MMboe. The year-end remaining reserves have consequently been revised down to 361.0 Bcf of gas and 0.6 MMbbl of condensate (total 60.7 MMboe).

Georgievskoye Exploration Licence

Most of the Oxfordian 2P reserves in the new licence area were already expected to be recoverable through existing wells on the field, but a further 30-90 Bcf of contingent Oxfordian resources could be recovered by additional drilling, together with a total 140-180 Bcf of Callovian resources.

In 2013, Krasnodar Geofizika reprocessed and re-interpreted the existing 2D dataset in the licence. Data density was insufficient to map any leads or prospects but the quality was sufficient to identify a number of seismic anomalies in the Oxfordian which are analogous to the Koshekhablskoye productive area.

Outlook

These leads are now being prioritised by size and depth (some are approaching the 5,700m depth of well-15) before finalising the 2014 2D and/or 3D seismic programme which will be shot at the end of the year after the harvest.

The licence carries a two well obligation and there is a "drill or drop" clause requiring these wells to be drilled, or not, before the licence expires or is renewed in 2017.

OPERATIONS REVIEW - HUNGARY

Hernád (I and II) Exploration Licences and Gorbehaza Mining Plot (development and production licence) (JKX 50%)

2013 update

The Hajdunanas and Gorbehaza fields produced from three wells (Hn-1, Hn-2 and Gh-1) into a single separator, and then via a 14.5 km export line to an existing facility for input to the Hungarian gas pipeline system.

· Well Hn-1, having been recompleted as a Miocene oil producer with new separation facilities, began production in June 2012 and averaged 60 bopd with 380 bwpd through December 2012 before liquid loading stopped production just before the year-end. Attempts were made to recommence production but were unsuccessful.

· Well Hn-2 was restarted in February 2013 and produced at around 0.5 MMcfd with almost 800 bwpd but eventually stopped producing in late 2013.

· The Gh-1 well is no longer producing.

Outlook

Well Hn-9 was planned as an infill development well for drilling in 2013 with the fractured Miocene oil reservoir as the primary target and a secondary target of potential attic gas within the Pannonian Pegasus sand interval. Unfortunately, the operator decided not to proceed with the drilling programme.

Hajdunanas and Gorbehaza production and Reserves

Average gross production in 2013 was 66 boepd (JKX net: 33 boepd) comprising 0.4 MMcfd of gas and 4 bpd of oil and condensate, a significant decrease on the average for 2012.

The continuing water influx in the main Pannonian gas reservoirs has virtually curtailed the field life with the remaining potential being confined to the Miocene oil reservoir and some attic gas from the Pannonian.

Remaining gross reserves in the field are now 0.52 Bcf and 0.12 MMbbl (JKX net 0.1 MMboe).

Hernád Exploration Activity

JKX holds a 50% equity interest in the two Hernad licences in the northern Pannonian Basin. There was a voluntary 1,076 sq. km partial relinquishment of the Hernad I licence in 2012 leaving a total of 1,827 sq. km; the Hernad II licence area is unchanged at 2,509 sq. km. Reprocessing of the 2011 Jaszsag area 3D seismic data was completed in 2012.

The 3D seismic has been reinterpreted and a shallow prospect, Tisvaszvari-15, identified for drilling in 2013. Unfortunately, the operator decided not to proceed with the project.

Outlook

JKX continues to see further potential in the field and in the exploration licences where there is at least one prospect ready to drill. If successful, this well could be tied back to the production facility and help extend the field life, in parallel with the well Hn-9 potential.

Sarkad I Mining Plot (JKX 25%)JKX retains its 25% interest in the 15.6 sq. km farm-in area around the Nyekpuszta-2 gas condensate discovery well.

The Operator remains keen to appraise the discovery but has made little progress in 2013. JKX is considering its options.

Turkeve IV Mining Plot (JKX 50%)The operator continued to evaluate various treatment and development options through 2013 but nothing has been settled and no date can be given for production to commence. JKX is considering its options.

Turkeve reserves

Based on the proposed development plan, gross Turkeve 2P reserves are 3.2 Bcf and 70Mbbl condensate (net to JKX 0.3 MMboe).

OPERATIONS REVIEW - SLOVAKIA

Svidnik, Medzilaborce and Snina licences (JKX 25%)

JKX holds a 25% interest in the Svidnik, Medzilaborce and Snina exploration licences, covering a total area of 2,278 sq. km in the Carpathian Fold Belt in north east Slovakia.

Acquisition of 500 km of 2D seismic data in 2008 through 2010 provided basic regional information in the two eastern licences, as well as infill data in the western Svidnik licence.

The Cierne-1 exploration well location in the westernmost Svidnik licence has been identified. The well would be drilled to more than 3,500m with a multiple targets identified in this sub-thrust play.

The original operator, Aurelian Oil & Gas plc, was taken over by San Leon Energy plc in 2013.

Outlook

San Leon has indicated that it plans to withdraw from the licence. This would leave JKX and Romgas with 50% each. Both companies would prefer to bring in a third partner prior to drilling the Cierne-1 well, the deadline for which has been extended by two years to 2016.

OPERATIONS REVIEW - BULGARIA

Provadia licence (JKX 18%)

JKX had an 18% carried interest in the 1,787 sq. km Provadia licence operated by Overgas.

Evaluation of the 2011/12 and 2013 2D seismic surveys revealed little of interest and in 2012 JKX indicated its intention to withdraw from the licence.

This finally became effective in January 2014 and JKX no longer has any interests in Bulgaria.

PRINCIPAL RISKS AND UNCERTAINTIES

2013 Risk update

The principal risks facing the Group have not changed significantly from those detailed in the 2012 Annual Report. However our overall assessment of those risks has changed in 2013 as follows:

· Geopolitical risk and the associated risk to our future gas prices in Ukraine have increased. The price at which we can sell our gas in Ukraine is set according to the Russia-Ukraine gas border price which is determined by a long-term gas sales agreement between the two governments. Following the well-publicised temporary amendment to the gas price agreement in December 2013 whereby Gazprom (Russia) supplied gas to Ukraine at a reduced price, the industrial gas price in Ukraine was reduced by 11% for Q1 2014. Following recent events in Ukraine Gazprom has revoked this discount and we expect gas prices to revert to 2013 levels in Q2 2014.

· Geopolitical risk has increased as Ukraine has experienced heightened political and social tensions in recent months which have not impacted the Group's operations to date but continue to be closely monitored.

· Reservoir performance risk has increased as the production from the Rudenkovskoye field after the multi-frac was at lower end of expectations; analysis of data and development plans for a potential second frac continue. In Russia we continue to remediate the recent well integrity issues however, in contrast, initial production rates at our Elizavetovskoye field experienced in January and February 2014 were significantly in excess of expectations.

· Reserves replacement risk has increased this year as key projects planned that may materially enhance the Group reserves and production include the assessment of our deeper sandstone reservoirs at Elizavetovskoye field and the full development of our Rudenkovskoye field in Ukraine, and the assessment of our deeper Callovian reserves in Russia, all of which may take some time to complete. Future reserves replacement may also come from asset acquisitions and our business development activity continues in the region to identify potential opportunities.

· The risk rating assigned to capital expenditure has decreased as our capital expenditure is lower in 2013 and we have improved the control environment and local training in our AFE system. We continue to develop and closely monitor and control capital costs across all our operations as we continue with investment in important capital intensive projects.

Despite the devaluation in the Ukrainian Hyrvna in early 2014 and recent depreciation in the value of the Russian Rouble, the foreign exchange risk rating has remained unchanged as neither have had any significant financial effect on the Group to date. Additionally, increased gas sales revenues in Russia are now partially mitigating the exposure of our local cost to the Rouble/$ fluctuations.

The principal risks and how we manage them are set out in detail in the Annual Report and are not in any order of priority, are likely to change, and do not comprise all the risks and uncertainties that the Group faces.

Directors' Responsibility statement

We confirm that to the best of our knowledge:

- the financial statements, prepared in accordance with the relevant financial reporting framework, give a true and fair view of the assets, liabilities, financial position and profit or loss of the Company and the undertakings included in the consolidation taken as a whole; and

- the management report, which is incorporated into the Directors' report, includes a fair review of the development and performance of the business and the position of the Company and the undertakings included in the consolidation taken as a whole, together with a description of the principal risks and uncertainties that they face.

Consolidated income statement

for the year ended 31 December

Consolidated statement of comprehensive income

for the year ended 31 December

Items in the statement above are disclosed net of tax.

Consolidated statement of financial position

as at 31 December

Consolidated statement of changes in equity

1 The share option reserve has been included within the retained earnings reserve.

2 Shares held by JKX Employee Benefit Trust.

Consolidated statement of cash flows

for the year ended 31 December

1. General information

The consolidated financial information for JKX Oil & Gas plc (the 'Company') and its subsidiaries (together 'the Group') set out in this preliminary announcement has been derived from the audited consolidated financial statements of the Group for the year ended 31 December 2013 (the 'financial statements').The auditors have reported on the 2013 financial statements and their report was unqualified. The financial statements are yet to be delivered to the Registrar of Companies.

The 2013 Annual Report was approved by the Board of Directors on 26 March 2014, and will be mailed to shareholders in April 2014. The financial information in this statement is audited but does not have the status of statutory accounts within the meaning of Section 434 of the Companies Act 2006.

Full accounts for JKX Oil and Gas plc for the year ended 31 December 2012 have been delivered to the Registrar of Companies. The Auditors' report on the full financial statements for the year to 31 December 2012 was unqualified and did not contain statements under Section 498 (1) (regarding adequacy of accounting records and returns), or under Section 498 (3) (regarding provision of necessary information and explanations) of the United Kingdom Companies Act 2006.

2. Basis of preparation

The financial statements have been prepared in accordance with International Financial Reporting Standards ('IFRSs') as adopted for use in the European Union. The accounting policies used by JKX Oil and Gas plc (the 'Group',) are consistent with those set out in the 2012 Annual Report. A full list of accounting policies will be presented in the 2013 Annual Report.

The financial information has been prepared on a going concern basis following review by the Directors of forecast cash flows for the next 12 months.

3. Segmental analysis

The Group has one single class of business, being the exploration for, evaluation, development and production of oil and gas reserves. Accordingly the reportable operating segments are determined by the geographical location of the assets.

There are four (2012: five) reportable operating segments which are based on the internal reports provided to the Chief Operating Decision Maker ('CODM'). Ukraine and Russia segments are involved with production and exploration; the 'Rest of World' are involved in exploration, development and production and the UK is the home of the head office and purchases material, capital assets and services on behalf of other segments. The 'Rest of World' segment comprises operations in Hungary, Bulgaria and Slovakia. Hungary is no longer considered a separate segment by the CODM due to the decline in the production rates and the impairment charge at 31 December 2012. Therefore Hungary has been included under the 'Rest of the World' segment. Transfer prices between segments are set on an arms length basis in a manner similar to transactions with third parties. Segment revenue, segment expense and segment results include transfers between segments. Those transfers are eliminated on consolidation.

Segment results and assets include items directly attributable to the segment. Capital expenditures comprise additions to property, plant and equipment and intangible assets.

There is 1 (2012: 1) customer in the Ukraine that exceeds 10% of the Group's total revenues.

4. (a) Property, plant and equipment

*Finance costs that have been capitalised within oil and gas properties during the year total $1.7m (2012: $2.5m), at a weighted average interest rate of 18.0 per cent (2012: 25.2 per cent).

Oil and gas fields in Ukraine and Russia include $6.3m and nilrespectively relating to items under construction (2012: $9.1m and nil). 

Exceptional item in 2012 - accelerated depreciation of Ukrainian oil and gas assets

Following the change in the Group's oil and gas reserves at the Novo-Nikolaevskoye Complex on 31 December 2011, and subsequent revision to future production plans from those fields during 2012, there was a reassessment of the expected future economic benefit from the Complex's oil and gas assets in Ukraine. As a result, during 2012, certain oil and gas assets became obsolete and therefore their carrying values were written off. A one-off accelerated depreciation charge of $30.7m was recognised in the prior year's consolidated income statement in respect of these oil and gas assets.

4. (b) Intangible assets: exploration and evaluation expenditure

The amounts for intangible exploration and appraisal assets represent costs incurred on active exploration and appraisal projects.

In 2013, the write off of exploration and evaluation costs comprises seismic data costs of $1.4m (2012: nil) in Hungary and exploration costs of $0.1m (2012: $0.2m) in respect of our Turkeve licence in Hungary.

The total write off of unsuccessful exploration and evaluation costs of $1.5m (2012: $4.9m) was recognised in Cost of sales.

4. (c) Impairment test for Property, plant and equipment

A review was undertaken at the reporting date of the carrying amounts of property, plant and equipment to determine whether there was any indication of a trigger that may have led to these assets suffering an impairment loss. Following this review impairment triggers were noted in relation to Yuzhgazenergie ('YGE') in Russia. See note 4(d) for the results of the YGE impairment test and consideration of the carrying value at 31 December 2013.

Indicators of impairment were noted in respect of our Hungarian assets (see note 4 (e)). No other impairment triggers were noted.

4. (d) Impairment test for Yuzhgazenergie ('YGE'), Russia

Following the 2007 acquisition of YGE in Russia, a technical and environmental re-evaluation of YGE's Koshekhablskoye gas field redevelopment was undertaken by the Group. The re-evaluation resulted in a revised development plan and production profile. The development plan and production profile have continued to be refined since that time.

For purposes of testing for impairment triggers of YGE's non-current assets, the Company took account of developments since the last test for impairment in 2011, based on the assessment of fair value less costs to sell.

In previous estimates, the Company has assumed net-back convergence with European gas prices occurring in 2020 after applying the Russian government's stated intention to increase gas sector tariffs annually by 15% on 1 July 2013 and through 2015, and by a lower increment in the years thereafter to achieve European net-back price convergence.

In 2013, following the introduction by the Russian government of a new mechanism of gas price adjustment which is linked to the calculated price at which gas has been exported in the previous quarter, our estimates of the anticipated convergence of Adygean gas prices to net back European levels has been delayed from 2020 to 2023. This revision to our estimate in the timing of convergence constituted an impairment trigger. Accordingly an impairment test was undertaken. 

The test compared the recoverable amount of the Cash Generating Unit ('CGU'), being YGE for the purpose of the review, to the carrying value of the CGU.

The estimate of recoverable amount was based on fair value less costs to sell, using a discounted cash flow ('DCF') methodology. The DCF was derived by estimating discounted after tax cash flows for the CGU based on estimates that a typical market participant would use in valuing such assets. In accordance with IAS 36, the impairment review was been undertaken in Russian Roubles.

Key Assumptions - Russia

The key assumptions used in the impairment testing were:

· Production profiles: these were based on the latest available information provided by independent reserve engineers, Senergy (GB) Limited, at 31 December 2012, and reassessing these internally to 31 December 2013. Such information included 3P reserves of 64.3 MMboe

· Economic life of field: it was assumed that YGE will be successful in extending the licence term beyond its current 2026 expiration to the economic life of the field (expected to be around 2059). The discounted cash flow methodology used has not taken account of any opportunities that may exist to extract reserves in a shorter timeframe by investing to increase the current plant capacity.

· Gas prices: for 2014 these were based on the gas sales agreement that the Company had negotiated with Kubangazifikatziya for the forecast gas production in 2014. The price is uplifted from 1 July by the expected increase in the regulated price on which the contract price is based.

· Gas prices: for 2015 and thereafter, the gas price increases were based on Russian regional gas market price expectations and the Russian government's stated intention to achieve net-back convergence with the European gas markets. The principle of achieving European net-back parity is the driver of regulatory price change in Russia and it was originally anticipated that this would be achieved by 2011, later revised to 2015 and subsequently 2017. Due to the recent sustained period of high international oil prices and hence high European gas prices, it is now unlikely to achieve parity in this time-frame. The Company has assumed net-back convergence occurring in 2023 based on internal estimates of European gas prices and applied gas sector tariff increases of 10.0% annually to achieve this, recognising that this is a lower growth rate than in any year since the goal of export net-back was defined by the Russian government in 2006.

· Gas prices: historically, gas prices in the Adygea Region are higher than the average gas price across all regions in Russia as a result of the vast transportation distances from Russia's main producing regions. The Company has assumed that that Adygean gas prices will remain higher than the average price across Russia.

· Gas prices: the gas price was assumed to increase in line with forecast Rouble inflation after 2023 consistent with operating cash flow assumptions.

· Capital and operating costs: these were based on current operating and capital costs in Russia, project estimates provided by third parties and supported by estimates from our own specialists, where necessary.

· Post tax nominal Rouble discount rate of 12.3%. This was based on a Capital Asset Pricing Model analysis consistent with that used in previous impairment reviews.

The Company's estimates also reflect the Russian government's recent confirmation of gas production tax rates which come into effect on 1 July 2014.

Based on the key assumptions set out above YGE's recoverable amount exceeds its carrying value by $127m and therefore YGE's Koshekhablskoye gas field was not impaired.

Any impairment is dependent on judgement used in determining the most appropriate basis for the assumptions and estimates made by management, particularly in relation to the key assumptions described above. Sensitivity analysis to likely and potential changes in key assumptions has therefore been reviewed below.

The impact on the impairment calculation of applying different assumptions to gas prices, production, future capital expenditure and post-tax discount rates, all other inputs remaining equal, would be as follows:

Sensitivity Analysis

4. (e) Impairment test for Hungarian oil and gas assets

HHE North Kft ('HHN'), Hungary

During 2013, the two producing Hungarian wells on our Hernad field experienced an unexpected decline in production rates:

· well Hn-1, stopped production in late 2012 and attempts to recommence production during 2013 have been unsuccessful

· well Hn-2 was restarted in February 2013 but had eventually stopped producing by the end of the year.

The unexpected decline in production from these two wells was considered to constitute an impairment trigger and a full impairment test was undertaken in respect of our oil and gas assetsrelating to the Hernad field.

The test compared the recoverable amount of the Hernad field Cash Generating Unit ('CGU'), which contained these two wells and which is held by HHN, the subsidiary which holds our Hungarian assets, to the carrying value of the CGU. The estimate of recoverable amount was based on fair value less costs to sell, derived by estimating discounted after tax cash flows for the CGU based on estimates that a typical market participant would use in valuing such assets. In accordance with IAS 36, the impairment review was undertaken in US$ being the functional currency of our Hungarian operations.

The key assumptions used in the impairment testing in 2013 were:

· Production profiles: these were based on the latest available information provided by our reserve engineers based on reserve information from the operator and external engineers, such information included 3P reserves of 0.3 MMboe

· Oil and gas prices: these were based on current prices being realised and short term price curves derived from expectations in the Hungarian oil and gas market

· Capital and operating costs: these were based on project estimates provided by third parties and the partner and operator of our Hungarian assets.

The post tax discount rate of 10% was applied. This was based on a Capital Asset Pricing Model analysis for our Hungarian assets.

Accordingly the impairment review is dependent on judgement used in determining the most appropriate basis for the assumptions and estimates made by management, particularly in relation to the key assumptions described above. Sensitivity analysis to likely and potential changes in key assumptions has therefore been reviewed below.

Based on the key assumptions set out above HHN's recoverable amount exceeds its carrying value by $1.0m and therefore HHN's oil and gas assets in respect of the Hernad field were not impaired.

The impact on the impairment calculation of applying different assumptions to production, oil and gas prices and future capital and operating costs, all other inputs remaining equal, would be as follows:

Exceptional item in 2012 - impairment of Hungarian oil and gas assets

HHE North Kft ('HHN'), Hungary

During 2012, two of our producing Hungarian wells experienced an unexpected decline in production rates:

· well Gh-1 watered out and following a review with our partner there are currently no plans to attempt to rectify this

· well Hn-2 watered out but following remediation work this well has been restarted at lower production rates than previously experienced.

We reduced our future production forecasts and reserves in respect of these two wells which the Company considered constituted an impairment trigger and a full impairment test was undertaken in respect of our Hungarian oil and gas assets.

The test compared the recoverable amount of the Hernad field Cash Generating Unit ('CGU'), which contained these two wells and which is held by HHN, the subsidiary which holds our Hungarian assets, to the carrying value of the CGU. The estimate of recoverable amount was based on fair value less costs to sell, derived by estimating discounted after tax cash flows for the CGU based on estimates that a typical market participant would use in valuing such assets. In accordance with IAS 36, the impairment review was undertaken in US$ being the functional currency of our Hungarian operations.

The key assumptions used in the impairment testing in 2012 were:

· Production profiles: these were based on the latest available information provided by our reserve engineers based on reserve information from the operator and external engineers, such information including 2P reserves (0.2 MMboe), 3P and contingent resources

· Oil and gas prices: these were based on current prices being realised and short term price curves derived from expectations in the Hungarian oil and gas market

· Capital and operating costs: these were based on project estimates provided by third parties and the partner and operator of our Hungarian assets.

No value was attributed to 3P and contingent resources. The post tax discount rate of 10% was applied. This was based on a Capital Asset Pricing Model analysis for our Hungarian assets. Accordingly the impairment test was dependent upon judgment used in determining such assumptions.

The changes in the key assumptions used from previous periods resulted in the oil and gas assets being impaired by $15.1m. The Group recognised the impairment charge within Cost of sales during 2012. The associated tax effect on the exceptional charge was a net deferred tax credit to the income statement of $4.8m during 2012.

The impact on the impairment calculation of applying different assumptions to production, oil and gas prices and capital and operating expenditure would have been as follows:

5. Borrowings

Convertible bonds due 2018

On 19 February 2013 the Company successfully completed the placing of $40m of guaranteed unsubordinated convertible bonds with institutional investors which are due 2018 raising cash of $37.2m net of issue costs.

The Bonds have an annual coupon of 8 per cent per annum payable semi annually in arrears. The Bonds are convertible into ordinary shares of the Company at any time from 1 April 2013 up until seven days prior to their maturity on 19 February 2018 at a conversion price of 76.29 pence per Ordinary Share, unless the Company settles the conversion notice by paying the Bondholder the Cash Alternative Amount (see below).

Interest, after the deduction of issue costs and the inclusion of the redemption premium, will be charged to the income statement using an effective rate of 18.0%.

Cash Alternative Amount

At the option of the Company, the conversion notice in respect of the Bonds can be settled in cash rather than shares, the Cash Alternative Amount payable is based on the Volume Weighted Average Price of the Company's shares prior to the conversion notice.

Credit facility

On 31 March 2011, Poltava Petroleum Company ('PPC'), our subsidiary in Ukraine, entered into a reducing credit facility agreement with Crédit Agricole CIB (France) secured by indemnity provided by the parent company, JKX Oil & Gas plc. The credit facility is for a maximum of Ukrainian Hryvnia equivalent of $15.0m. The facility was renewed on 26 April 2013 and is available until 30 June 2014 (2012: 30 June 2013) with the maximum facility reducing to $10.0m and $5.0m on 30 April 2014 and 30 May 2014 respectively. All provisions contained in the credit facility documentation have been negotiated on normal commercial and customary terms for such finance arrangements. The interest is calculated at prevailing Crédit Agricole CIB (France) bank rate plus a margin.

At the reporting date none of the Credit Facility had been drawn down.

6. Derivatives

Non-current derivative financial instruments

Convertible bonds due 2018 - embedded derivatives

Coupon Makewhole

Upon conversion of a Bond prior to the 19 February 2015 the Company is required to pay an amount of interest equal to the aggregate interest which would have been payable on the principal amount of the Bond if such Bond had been outstanding until 19 February 2015.

Bondholder Put Option

Bondholders have the right to require the Company to redeem the following number of Bonds on the following dates together with accrued and unpaid interest to (but excluding) such dates:

Current liabilities include $4,000,000 (2012: nil) in respect of the put option available to bondholders on 19 February 2014. None of the bondholders exercised their option to put 10% of the outstanding principal of the bonds on 19 February 2014.

Company Call Option

The Company can redeem the Bonds early in full but not in part at their principal amount together with accrued interest at any time on or after 19 February 2017 if the Volume Weighted Average Price of the Company's shares over a specified period equal or exceed 130 per cent of the principal amount of the Bonds; or if the aggregate principal amount of the bonds outstanding is less than 15% of the aggregate principal amount originally issued.

Fixed exchange rate

The Sterling-US Dollar exchange rate is fixed at £1/$1.5809 for the conversion and other features.

7. Taxation

Factors that affect the total tax charge

The total tax (credit)/charge for the year of $2.5m (2012: $13.0m) is lower (2012: higher) than the average rate of UK corporation tax of 23.25% (2012: 24.5%). The differences are explained below:

The current tax charged in the year of $8.6m mainly relates to Ukrainian corporation tax which has arisen in the Group subsidiary, Poltava Petroleum Company. Taxes charged on production of hydrocarbons in Ukraine and Hungary are included in cost of sales. The standard rate of corporation tax in the UK changed from 24% to 23% with effect from 1 April 2013. Accordingly, the Company's profits for this accounting period are tax at an effective rate of 23.25%.

Factors that may affect future tax charges

A significant proportion of the Group's income will be generated overseas. Profits made overseas will not be able to be offset by costs elsewhere in the Group. This could lead to a higher than expected tax rate for the Group.

Finance Act 2012 reduced the main rate of corporation tax to 23% from 1 April 2013. The UK corporation tax rate changes announced in the 2012 Autumn Statement and March 2013 Budget were substantively enacted as part of the Finance Bill 2013 on 2 July 2013. These include reductions to the main rate of UK corporation tax to 21% for the financial year commencing 1 April 2014 and 20% for the financial year commencing 1 April 2015.

The impact of the rate reduction is not expected to have a material impact on provided and unprovided UK current or deferred taxation.

The corporation tax rate in Ukraine for 2013 was 19% and this rate remains in place for 2014.

Taxation in Ukraine - production taxes

The Group is subject to uncertainties relating to the determination of its tax liabilities. Ukrainian tax legislation and practice are in a state of continuous development, with new laws coming into effect at times which can conflict with others and, therefore, are subject to varying interpretations and changes which may be applied retrospectively. 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 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.

Since PPC's inception in 1994 the Company has operated in a regime where conflicting laws have often existed, including in relation to effective taxes on oil and gas production. Various laws and regulations have existed and have implied a number of variable rates.

PPC has at times since 1994 sought clarification of their status regarding a number of production related taxes, and has been subject to a number of such taxes, at various rates, which have been paid and accounted for within Operating Costs within the Group Income Statement. In late 2009, coinciding with the lead up to the Presidential election in Ukraine, PPC was subjected to increased operational pressures in several areas, including broader taxation.

On 1 January 2010 yet another law came into force in Ukraine in the area of production related tax, the Law of Ukraine on "On Rent Charges for Oil, Natural Gas and Gas Condensate" which had been suspended since 2004. During 2010 conflicting laws were announced (most particularly the Law of Ukraine on "Amending Certain Legislative Acts of Ukraine") which may be a basis for the Ukrainian Tax Authorities to assert that further production related taxes are due from various oil and gas companies, including PPC, for periods through to 31 December 2010.

PPC continues to defend itself in court against action initiated by the tax authorities concerning rules of calculation and payment of various production related taxes for the period from January to March 2007 and from August 2010 to December 2010. The statutory period of limitation in Ukraine for such matters is three years. If PPC was subject to maximum production related taxes for the periods from January to March 2007 and from August 2010 to December 2010, additional production related taxes could be approximately twenty per cent of Ukraine gross revenues for those periods (net of corporate tax savings), plus interest and penalties. The Group considers that the likelihood of paying additional production related taxes for these periods is remote on the basis of tax audits completed, the related legal position together with arguments that the Group has to defend its position, and the three year statute of limitation. No provision has been made for the possible future liabilities that may result from these tax uncertainties.

A new tax code became effective in Ukraine on 1 January 2011 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 has paid, rental fees during the period. The fees are levied on production volumes in accordance with a rates schedule which may change from time to time. Such payments are recorded in cost of sales.

8. Earnings/(loss) per share

The calculation of the basic and diluted earnings/(loss) per share attributable to the owners of the parent is based on the weighted average number of shares in issue during the year of 172,163,992 (2012: 172,070,477) and the profit/(loss) for the relevant period.

The diluted earnings per share for the year is based on 174,519,492 (2012: 173,317,487) ordinary shares calculated as follows:

Earnings before exceptional item in 2012 of $24,701,965 is calculated from the 2012 loss of $11,335,000 and adding back exceptional items of $45,816,000 less the related deferred tax on the exceptional items of $9,779,000.

In accordance with IAS 33 (Earnings per share) the effects of antidilutive potential have not been included when calculating dilutive earnings per share for the year end 31 December 2013. 28,792,122 potentially dilutive ordinary shares associated with the convertible bonds (note 5) have been excluded as they are antidilutive in 2013, however they could be dilutive in future periods. 

There were 6,549,300 (2012: 3,499,863) outstanding share options at 31 December 2013, of which 2,355,500(2012: 1,247,010) had a potentially dilutive effect.

9. Events after the reporting date

Start-up of the Elizavetovskoye Field, Ukraine

The first export of gas from our stand-alone Elizavetovskoye field development took place on the 15 January 2014 following the successful completion of the first development well E-301. In March 2014, the second development well on the Elizavetovskoye field, E-302, was completed and placed on production. The wells are now flowing gas to the newly commissioned early production facility which is located 35 km to the southeast of Poltava, Ukraine.

Drilling of the next well on the field, E-304, is planned for the third quarter of 2014 and will target the deeper G sands reservoirs.

Operations in Ukraine and Russia

Poltava Petroleum Company is the Company's wholly-owned operating subsidiary in Ukraine. Its operations are located in central Ukraine in Poltava, 200 miles south-east of Kiev. The Company also has a wholly-owned operating subsidiary, Yuzhgazenergy LLC, in the southern Russian Republic of Adygea. We are monitoring the current political situation between Ukraine and Russia carefully and there have been no disruptions to the Company's operations in either of our operating locations. Our focus remains our staff and customers in Ukraine and Russia where all our oil and gas is sold to private sector buyers in their respective domestic markets.

We have reassessed the key judgements and critical accounting estimates as at the date of this report and, based on the current status of operations, no adjustments have been made.

Glossary

2P reserves Proved plus probable

3P reserves Proved, probable and possible

P50 Reserves and/or resources estimates that

have a 50 per cent probability of being met

or exceeded

AFE Authorisation For Expenditure

AIFR All Injury Frequency Rate

Bcf Billion cubic feet

Bcm Billion cubic metres

bcpd Barrel of condensate per day

boe Barrel of oil equivalent

boepd Barrel of oil equivalent per day

bopd Barrel of oil per day

bpd Barrel per day

bwpd Barrels of water per day

cfpd Cubic feet per day

EPF Early Production Facility

GPF Gas Processing Facility

HHN HHE North Kft

Hryvnia The lawful currency of Ukraine

HSECQ Health, Safety, Environment, Community and Quality

KPI Key Performance Indicator

LIBOR London InterBank Offered Rate

LPG Liquefied Petroleum Gas

LTI Lost Time Injuries

Mbbl Thousand barrels

Mboe Thousand barrels of oil equivalent

Mcf Thousand cubic feet

MMcfd Million cubic feet per day

MMbbl Million barrels

MMboe Million barrels of oil equivalent

PPC Poltava Petroleum Company

Roubles The lawful currency of Russia

sq.km Square kilometre

TD Total depth

$ United States Dollars

US United States

VAT Value Added Tax

YGE Yuzhgazenergie LLC

Conversion factors 6,000 standard cubic feet of gas = 1 boe