JKX.L Regulatory News (JKX)

FOR IMMEDIATE RELEASE 9 APRIL 2013

JKX Oil & Gas plc

FINAL RESULTS

 FOR THE YEAR ENDED 31 DECEMBER 2012

Key Financials

·; Group revenue $202.9m (2011: $236.9m)

·; Group production 8,281 boepd (2011: 9,045 boepd)

·; Gas realisations in Ukraine $12.1/Mcf (2011:$9.6/Mcf)

·; Cash flow from operations $109.3m (2011: $124.2m)

·; Operating profit (before exceptional charges) $51.6m (2011: $82.0m)

·; Non-cash exceptional charges of $45.8m (2011: nil)

·; Capital expenditure $67.3m (2011: $162.0m)

Operational Highlights

·; Commercial gas sales and ramp-up of production from Koshekhablskoye field in Russia

·; Upward revision of 2P reserves to 93.8 MMboe, a reserves replacement ratio of 208%

·; Award of Rudenkovskoye multi-stage frac contract, execution Q2 2013

·; Frac preparation work nearing completion at well R-103 in Rudenkovskoye, Ukraine

·; Approval of the Elizavetovskoye field development plan in Ukraine

·; Successful exploration drilling at Zaplavskoye exploration licence in Ukraine encountering highly productive reservoirs

Outlook

·; Solid financial platform following repayment of short term debt and completion of a $40m 5-year convertible bond

·; Fully-funded development programmes in both Ukraine and Russia

·; Focus in Russia now on expansion of plant capacity to 60 MMcfd at minimum capital cost

·; Strong gas realisations in Ukraine expected to be maintained through 2013

·; Continued focus on growth opportunities in the gas markets in Ukraine and Russia

JKX Chief Executive, Dr Paul Davies, commented: 

"2012 was a challenging year for the Company as we managed both production delays in Russia and reduced liquidity resulting from retirement of short-term debt.

Commercial gas sales at our Russian plant commenced in April 2012 and current production rates are in excess of 40 MMcfd. We have continued to benefit from strong and stable oil, condensate, gas and LPG realisations in Ukraine.

The Company's development programmes in both Ukraine and Russia are now fully-funded following the successful placing of $40million of convertible bonds in January of this year.

We have begun an important growth phase of the Company with a reversal of the recent production decline in Ukraine and the continued growth of our new Russian production."

ENDS

For further information please contact:

Nadja Vetter / Alexandra Stoneham Cardew Group 020 7930 0777

A presentation to analysts will be held at 9.30am at Oriel Securities, 150 Cheapside, London EC2V 6ET. The presentation will be available at http://www.jkx.co.uk from 8.30am.

Chairman's statement

A Challenging Period

2012 was a challenging year for the Company as we managed both production delays in Russia and reduced liquidity resulting from retirement of short-term debt. I am pleased to report that the Company's position going forward in 2013 is significantly improved with rising production and fully-funded development programmes in both Ukraine and Russia following the successful placing of $40 million of convertible bonds in January of this year.

We have benefited from strong and stable oil, condensate, gas and LPG realisations in Ukraine during the period which are anticipated to remain firm during 2013. Strong cash flow from our Ukrainian production continued to underpin the Company's investment programmes and will continue to do so in 2013.

Whilst ramp-up of production in Russia from field start-up in April was slower than expected, gas realisations grew in the period and are forecast to continue to trend upwards towards European netback convergence over the medium term. An increasing contribution to Group cash flow from our Russian operations can be expected through 2013 now that production has reached plant capacity.

Strategy

Your Company remains committed to eastern and central Europe as the focus of its activities, not only in terms of on-going operations and development but also as the preferred area for potential expansion and acquisitions.

Our traditional exploration and production market in Ukraine is currently experiencing a significant change in the State's attitude to foreign investment with the rapid implementation of changes to the nascent production sharing legislation; this is facilitating the participation of the large multi-nationals in both tight gas and shale gas plays. We believe this trend offers additional opportunities for our Ukrainian subsidiary to expand its operating footprint.

Growth in the independent gas sector in Russia continues apace, and I am pleased to report that our entry into the commercial gas market in southern Russia has been effected smoothly. The award of the large Georgievskoye exploration licence in May and its proximity to our Koshekhablskoye field provides evidence of the potential for the Company to build on its position in the region.

Development of our operating subsidiaries is a key element of our growth strategy. This goes hand in hand with the key role played by our staff, particularly those in our Ukrainian and Russian subsidiaries, in the strength and breadth of the overall capability of the Group. We are producing sour gas in Russia from deep reservoirs with very high pressures and temperatures, whilst in Ukraine this spring, we are undertaking one of the largest on-shore multi-frac operations in Europe. Our personnel are at the forefront of technical developments in the industry and are to be commended for the skill and dedication they bring to these complex projects.

The Company is justly proud of its outstanding record in 2012 for health, safety, environmental matters and community liaison. We achieved zero lost time injuries in more than 1.6 million manhours of safety exposure and our injury frequency rate is again well below the industry benchmark. Furthermore, in November the Company won the prestigious 2012 CIR Risk Management Award sponsored by the International Institution for Risk and Safety Management.

Performance

Group operations during the period continued to be underpinned by production from Ukraine, although this was supplemented by Russian production following start-up of the Koshekhablskoye field in April. Technical difficulties in Russia bringing the re-completed wells on-stream at design capacity resulted in lower than anticipated Group production for the year.

The Ukrainian exploration and development drilling programme at Poltava continued through the majority of the period with a notable success in the Zaplavskoye exploration licence. In the third quarter, we awarded to Schlumberger a contract for the large multi-frac of well R-103 in the deep tight gas Rudenkovskoye field. Pre-frac site preparation, materials procurement and equipment delivery proceeded satisfactorily into 2013 and we are on schedule for commencement of operations before mid-year. Gas production commenced from one of the legacy wells in the Elizavetovskoye licence during the second quarter and has yielded sufficient technical data to materially upgrade the 2P reserves for the field and to kick-off a five well stand-alone development of the licence in 2013.

Start-up of the Russian project in the second quarter was followed by the initiation of gas sales and the award of our Permit to Operate by the Russian authorities. Disappointingly, re-work of all three production wells has been necessary resulting in variable total production rates through the remainder of the reporting period. Well re-work continued through the first quarter of 2013, and has resulted in much improved rates of production.

We have completed a reserve review of our licence portfolio as of 31 December 2012, and I am pleased to announce that, after a total 2012 production of 2.8 MMboe, we have increased our 2P reserves to 93.8 MMboe (a reserves replacement ratio of 2.1).

Your Board

In July, I was voted unanimously by the Board to become Chairman, following Sir Ian Prosser's resignation to pursue other interests. I was delighted that Dipesh Shah agreed to assume the position of Senior Independent Director at that time, in addition to his role of Chairman of the Remuneration Committee.

At the New Year, Richard Murray joined the Board as non-executive director and has taken over the important role of Chairman of the Audit Committee. Richard brings to the Company a wealth of knowledge of mid-market companies gained from his long career with Ernst & Young, most latterly as Senior Audit Partner. I am certain that Richard's experience and expertise will be of great benefit to the Company.

Dividend

The Board has reviewed 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 

The successful bond financing at the beginning of this year is allowing the Company to proceed expeditiously with key projects aimed at raising production levels in both Ukraine and Russia.

Development drilling restarted in Ukraine at the end of the first quarter and will continue through the rest of this year to include the new Elizavetovskoye development and the further appraisal of the Zaplavskoye licence. The large Rudenkovskoye frac is on schedule for the second quarter, with results anticipated in the late July; I am optimistic that these will warrant the drilling of the next well on Rudenkovskoye.

The acidisation programme on the three Koshekhablskoye production wells in the first quarter has enabled production to reach the nominal plant capacity. The focus now moves for the remainder of the year to debottlenecking and expanding the Russian plant capacity, and a further increase of field production with completion of the workover of an additional well. Appraisal of the Callovian reservoir is also currently scheduled for the second half of the year.

Finally, I wish to thank all staff for their ongoing commitment to the Company's goals and aspirations and also our shareholders for their continuing support of the Company.

Nigel Moore

Chairman

Chief Executive's statement

Operational consolidation leading to rising production

2012 saw the start-up of the production from both our Koshekhablskoye project in southern Russia and from the Elizavetovskoye field in Ukraine. In Ukraine, we drilled our first successful exploration well on the Zaplavskoye licence and in Russia, we were awarded the large Georgievskoye exploration licence surrounding our Koshekhablskoye production licence.

Our performance

Average oil and gas production for the year decreased by 8% to 8,281 boepd (2011: 9,045 boepd) with slower than anticipated ramp-up of production in Russia failing to offset the predicted decline in production from our mature Ukrainian fields.

Group revenue for the year was lower at $202.9m (2011: $236.9m) and reflected both reduced overall production and lower gas realisations currently achievable in the Russia market. LPG revenues in Ukraine rose 71% to $18.6m (2011:$10.9m) as a result of a full year of production and continuing strong realisations.

Operating profit before exceptional charges declined 37% to $51.6m (2011: $82.0m); exceptional non-cash charges were $45.8m (2011: nil).

Our progress

As indicated in last year's report, 2012 was a year of operational consolidation with financial resources being stretched.

In southern Russia, we completed our key Koshekhablskoye project and entered the Russian gas market. The key targets of award of the Permit to Operate and successful commercial gas deliveries through the April to December period were achieved, although the build-up of production did not match our initial projections; further workovers of the three production wells proceeded sequentially through the period. We also were awarded the 170 sq. km Georgievskoye exploration licence in the second quarter which is contiguous with the Koshekhablskoye production licence.

Activity in Ukraine proceeded at a slower pace than we would have liked, again because of the need to manage our cash resources. However, development drilling continued on our production licences at Poltava through the first eight months of the year and we made a successful gas condensate discovery in our Zaplavskoye exploration licence. The exploration success in Zaplavskoye was followed up in the fourth quarter with acquisition of an additional 40 sq. km of 3D seismic over the Zaplavskoye location to identify appraisal drilling targets for this year.

Also at Poltava, preparatory work proceeded at well R-103 in the Rudenkovskoye gas field for the nine-stage multi-frac, including the award to Schlumberger for its execution in the second quarter of this year.

In late 2011 our Ukrainian subsidiary, PPC, secured an agreement with the well owner and former operator to work-over three legacy wells on the Company's Elizavetovskoye licence. PPC restored production from the first of these three wells in the second quarter of the period and the positive on-going production data gathered have allowed a significant upwards revision of the 2P reserves for the licence to 22 BCF (3.7 MMboe) with a further 20 MMboe of prospective resources. A five well stand-alone development of the licence is now underway (JKX: 100%).

Activity on the Company's non-operating interests in Hungary, Slovakia and Bulgaria were all at a low level during the period.

Our organisation

We made a number of key organisational and staffing changes through 2011 and these allowed the Company to achieve a number of important goals in 2012.

The new management at our Russian subsidiary, Yuzhgazenergy (YGE), has brought the important Koshekhablskoye project on-stream and has also led the important transition of the organisation from a construction project group to an operating company. This was achieved with significant input from both management and technical personnel from our mature Ukrainian operating company, PPC, in Poltava. We will seek to expand such operational synergies and skill exchanges between our subsidiaries going forward.

In Poltava, in-house design and upgrade work on both compressors and the LPG facility demonstrate the continuing growth of capability of PPC's technical and construction departments.

Managing our risks

Risk is intrinsic to our industry and we expend considerable resources and expertise in managing it. During 2012, we continued to strengthen our internal control and risk management processes and to embed these across all operations in the Group. Regular scheduled revision of our risk register and review of our procedures is an essential feature of this process, with continued oversight at Board level. We also ensure that existing policies and procedures are followed to comply with the UK Bribery Act and its guidance.

Outlook

Repayment of the $50 million Credit Suisse facility by the end of 2012 and successful placement of $40 million of convertible bonds with a 5 year maturity in January of this year has created a solid financial footing for the Company to accelerate its exciting development programmes in Russia and Ukraine over the next two years.

The Russian plant has now exceeded its nominal capacity of 40 MMcfd as a result of the successful acidisation programme of our three production wells in the first quarter of this year. The programme has demonstrated that each well is capable of producing between 13 MMcfd and 23 MMcfd with the current carbon steel tubing diameter.

A fourth producer (well-05) is currently being worked-over to provide not only a level of redundancy in the production stream, but also to facilitate the sequential change-out over the coming 18-month period of the carbon steel tubing and downhole chemical injection with a larger diameter corrosion resistant tubing, thus allowing significantly higher production rates per well. We are confident that this increase in production can be processed by debottlenecking the plant with a modest level of capital expenditure. In summary, the basis of the on-going capital programme in Russia over the 2013/2014 period is focused on increasing gas delivery to 60 MMcfd at minimum capital cost.

Development drilling at Poltava, Ukraine, restarted in March with the side-track of well M-166 in the Molchanovskoye field, and will be followed by an in-fill well on the Ignatovskoye field. The Skytop rig is then scheduled to move to the Elizavetovskoye licence in June to spud the first of the planned 5-well development drilling programme. Drilling is also planned in 2013 on the Zaplavskoye licence, following completion of processing and interpretation of the additional 3D seismic data shot in 2012. Work will also begin on the waterflood programmes on the Ignatovskoye and Molchanovskoye North fields, utilising the recently complete reprocessing of the 188.5 sq. km 3D seismic data set over the Novo-Nikolaevskoye complex.

As discussed above, the Company is well advanced with its preparations for the large multi-frac on well R-103 in the Rudenkovskoye field in the second quarter of this year. We remain cautiously optimistic this will be followed by a further well in Rudenkovskoye and the delineation of the development project for the full development of this very large gas resource.

We have begun an important growth phase of the Company with a reversal of the recent production decline in Ukraine and the continued growth of our new Russian production. I can assure all shareholders that your Board and all employees are fully committed to delivering rising production and improved results going forward.

Dr Paul Davies

Chief Executive

Financial Review 2012

Introduction

High commodity prices, particularly for Ukrainian gas and LPG, have continued to sustain our operating profits and cash flow in 2012 despite production volumes decreasing in Ukraine and well performance issues in Russia.

Revenues were lower at $202.9m (2011: $236.9m) mainly due to lower production volumes in Ukraine; this also impacted our cash generated from operations which reduced to $109.3m (2011: $124.2m). Profit from operations before exceptional items was $51.6m (2011: $82.0m).

In the first three months of 2012 we continued to invest in testing and commissioning our Russian gas plant which commenced commercial production and sales in April. The resultant revenue alleviated some of the cash requirements of our Russian operation however the subsequent well performance issues in Russia required additional capital expenditure and well intervention through the year resulting in lower than expected production volumes and sales.

In Ukraine we managed our capital spend through careful rescheduling of our drilling programme to support the short-term needs of the Russian well workovers. We were pleased to announce the restarting of our Ukrainian in-field drilling and appraisal programme from March 2013.

In December we settled all obligations under the short term finance provided by the prepaid swap which absorbed $40.0m in capital repayments and $7.1m of financing charges during 2012.

This left the Group with very little debt at the year end and provided the opportunity to put the Group's financial future on a firmer footing with longer term finance secured through a 5-year convertible bond which completed in February 2013.

Revenue

The Group continued to benefit from high oil and gas prices.

Group revenues of $202.9m (2011: $236.9m) were 14.4% down on prior year mainly as a result of a 24.8% diminished production in Ukraine. From a total revenue perspective, Ukrainian gas had the biggest impact on our revenue as it represented 60% (2011: 70%) of group volumes sold by boe.

Group revenues in 2012 by region comprised: Ukraine $191.1m (2011: $225.4m), Russia $5.1m (2011: nil) and Hungary $6.6m (2011: $11.3m).

Group gas sales volume in the year (excluding LPG) were a combined 7,462 boepd (2011: 8,978 boepd), with 79% (5,912 boepd) (2011: 95%, 8,536) sold in Ukraine, 18% (1,336 boepd) (2011:nil) attributable to Russia and the remaining 3% (214 boepd) (2011: 5%, 442) in Hungary.

The reduction in Group sales volume (excluding LPG) was partly offset by the 8.3% increase in average gas price realised of $10.55/Mcf (2011: $9.74/Mcf). Gas sales represented 75% (2011: 75%) of the Group's total boe volume sold.

Gas sales

Gas realisations in Ukraine improved by 26.0% to $12.1/Mcf (2011: $9.6/Mcf); this strengthening of Ukrainian gas price has supported Group revenues following the Ukrainian production decline.

On a boe basis, 99% of Russian sales volumes are gas. Russian gas realisations were $2.60/Mcf (2011: nil) which were less than a quarter of our Ukrainian gas realisations; therefore, they have a lower contribution to group revenues when compared with the respective sales volumes.

Oil sales

Oil sales comprise 23% (2011: 25%) of our total boe volume sold. Average oil realisations decreased by 4.8% from the prior year but remained high at $93.55/bbl (2011: $98.27/bbl) following international oil prices.

Group oil revenues declined due to a combination of lower oil realisations, a production decline of 22.0% on a boe basis due to reduced volumes from our Ukrainian wells, which was not offset by new production from a continuous drilling campaign as in previous years, and reduced production from Hungary.

LPG sales

Production volumes of LPG in combination with strong LPG prices contributed revenues of $18.6m (2011: $10.9m). The average price realised was $970/tonne (2011: $860/tonne).

Future Ukrainian and Russian Gas prices

Recent press contains much speculation concerning Ukrainian gas prices and the Ukrainian push for a renegotiation of the gas supply agreement between Russia and Ukraine; this has a direct impact on the industrial tariff that applies to our Ukrainian gas sales. The two countries continue to negotiate and consequently, the terms of the Supply Agreement of January 2009 still prevail.

This resulted in a border price of $416/Mcm throughout 2012, translating into the price of gas in the industrial market in excess of $430/Mcm (2011: $420/Mcm). In Q1 2013 we have continued to realise gas prices in Ukraine in excess of $420/Mcm.

The Ukrainian Parliament recently passed The Law of State Budget of Ukraine for 2013 on the assumption of a gas import price of $421/Mcm (2012: $416/Mcm).

In line with Russian government pronouncements, we currently expect the regulated wholesale industrial gas price in Adygea to increase annually at 15% through 2015 from their year end prices of 3,609 Roubles/Mcm.

Loss for the year

The loss after tax was $11.3m (2011: $59.1m profit) after exceptional charges (net of related tax effects) of $36.0m. Excluding the exceptional items the result for the year would have been $24.7m profit (2011: $59.1m).

The total depreciation, depletion and amortisation ('DD&A') charge (including exceptional items) for the year has increased to $84.4m (2011: $34.3m); this is a non-cash charge which reflects the expensing of the costs of developing our fields over their expected remaining period of production.

The pre-exceptional profit of $24.7m (2011: $59.1m) includes a non-cash DD&A charge on our Molchanovskoye field in Ukraine of $22.0m (2011: $9.5m).

At the end of 2011 there was a 90% reduction in the remaining reserves of our Molchanovskoye field.  The impact on the DD&A charge of a reduction in remaining reserves is accounted for by prospectively increasing the 2012 and future DD&A charge relating to this field to deplete the cost of remaining wells and facilities over the remaining reduced reserves. Therefore, the DD&A charge per boe produced from the Molchanovskoye field increased by over 500% this year.

As a result our pre-exceptional DD&A charge for the year is $18.4m higher than in the prior year as a direct result of the reserves reassessment of our Molchanovskoye field in Ukraine.

Exceptional items

Accelerated depreciation charge - $30.7m

Following the reduction in the Group's oil and gas reserves at our Novo-Nikolaevskoye Complex, and subsequent revision to future production plans from all four fields, certain oil and gas assets became redundant during the year and a one-off non-cash accelerated depreciation charge of $30.7m has been recognised in the income statement in respect of these assets.

Hungarian assets impairment - $15.1m

Following a more rapid production decline and the watering out of two out of three producing wells in Hungary, related reserves and estimated future production from our Hungarian assets have reduced.

We have recognised an impairment provision of $15.1m (2011: nil) against our Hungarian oil and gas assets to write down their carrying value to the estimated discounted present value of expected future cash flows.

Profit from operations before exceptional items

Profit from operations before exceptional items was $51.6m (2011: $82.0m).

This $30.4m reduction is the combined result of:

·; a $34.0m decrease in revenues mainly due to reduced Ukrainian oil and gas production

·; the benefit of a $19.7m decrease in production related taxes due to lower production volumes but also due to lower production based taxes of $16.70/boe (2011: $20.33/boe)

·; an increase of $19.6m in the non-cash DD&A charge to $51.9m (2011: $32.3m) mainly as a result of our reassessment of Ukrainian reserves in the prior year. The overall unit of production charge per boe increased to $18.30/bbl (2011: $9.80/bbl) (excluding exceptional DD&A charge)

·; an increase in operating charges of $7.6m to $24.9m (2011: $17.3m); $8.9m was as a result of Russia transitioning from being a construction company to an operating company in April which was off-set by $1.3m of cost reductions in other operating companies

·; an $8.0m reduction in the write off of exploration and evaluation costs to $4.9m (2011: $12.9m)

·; a $4.5m reduction in group administrative expenses to $21.2m (2011: $25.7m)

·; a $1.4m increase in foreign exchange losses.

Profit from operations

As noted above, also reducing Profit from operations are exceptional non-cash charges of $45.8m (2011: nil).

Finance income

Finance income has decreased slightly to $0.6m (2011: $0.9m) reflecting the low interest rate environment globally and the reduced cash deposits held by the Group.

Finance costs

Finance costs have increased by $3.9m to $4.8m (2011: $0.9m) during the year mainly as a result of the increase in the net $2.0m (2011: nil) effective interest charge on the prepaid swap which concluded in December. In addition bank interest payable increased $1.4m to $1.9m (2011: $0.5m) mainly relating to charges on the Credit Agricole working capital facility.

Earnings/(loss) per share

Basic earnings per share before exceptional items decreased 58.2% to 14.36 cents (2011: 34.37 cents) in line with the reduced pre-exceptional profit.

Basic loss per share after exceptional items was 6.59 cents (2011: earnings per share 34.37 cents) reflecting the group loss after exceptional items net of their related tax effects of $36.0m (2011: nil).

Taxation

The total tax charge for the year was $13.0m (2011: $22.9m) comprising a current tax charge of $18.9m (2011: $21.8m) and a deferred tax credit $5.9m (2011: charge $1.2m).

The fall in current tax charge of $2.9m 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%, 2013 at 19% and 16% from 1 January 2014.

Other taxation - general

There has been much speculation in the press during the year concerning royalties and corporation tax rates in both Ukraine and Russia which we continue to monitor closely.

The production based tax expense for the year is $47.4m (2011: $67.1m) and has been recognised in cost of sales. The reduction is due to the lower volumes produced, combined with a decline in effective production tax rates to $16.70/boe (2011: $20.33/boe).

Other taxation - Ukraine

During 2012 royalties, rental taxes and environment taxes were charged on our production. Changes to production taxes from 1 January 2013 were approved by parliament during the year and signed by the President. The royalties and rental costs regime 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 current production and border price levels this has increased our production tax rate on gas from $73.30/Mcm to $100.60/Mcm but reduced the production tax rate on oil from $37.70/bbl to $36.90/bbl.

Other taxation - Russia

Following commencement of commercial production in Russia, the Group has become exposed to a number of new operating costs including production taxes. Two new taxes which our Russian subsidiary has been paying in 2012 are the mineral extraction tax ('MET'), calculated using production volumes, and property tax which is based on the carrying value of our Russian gas plant.

After much public debate and speculation in Russia regarding the future MET rate, on 19 November the Russian government confirmed the MET increases through to 2015 which has the impact of increasing our current MET rate from 334 Roubles/Mcm to 552 Roubles/Mcm by 2015.

We expect developments around future gas prices and MET rates to be driven by the Russian government's need to encourage new investment into the Russian gas resource base to meet demand in Europe, Asia and domestically, in addition to supporting to the government's financial needs. 

Operating cash flow

The Group continued to reap the rewards of past investments with cash generated from operations of $109.3m (2011: $124.2m). This was 12.0% lower mainly due to lower production and sales in Ukraine.

On 12 January 2012, the Ukrainian government reduced the tax applicable to oil production decreasing it by 30% on a per barrel basis. This brought a welcome improvement to the Group's forecast cash flow, albeit minor in light of the level of our oil production in Ukraine.

Interest and swap charges paid were $6.5m higher at $8.9m (2011: $2.4m) mainly due to the finance charges on the short term prepaid swap facility. Total finance payments on the prepaid swap were $7.1m (2011: $1.7m).

Corporation tax paid was 4.0% lower at $21.8m (2011: $22.7m) mainly due to the reduction in corporation tax rates in Ukraine in 2012 to 21% (2011: 23%). In addition, there has been a reduction in corporation tax payable from $2.8m at the end of 2011 to $0.8m and a $1.3m increase in prepaid corporation tax (2011: nil); these payments in respect of past and future periods has increased the tax paid during 2012 by $3.3m.

Net cash generated from operating activities was $20.5m lower at $78.5m (2011: $99.0m) as a result of the $14.9m reduction in net cash from operations, a $6.5m increase in interest and swap payments and a reduction of $0.9m in corporation tax payments.

Cash flows from investing activities

Capital Expenditure - Property, Plant and Equipment

With our Russian plant completed and commissioned in April, the significant construction costs of 2010 and 2011 were not required in 2012.

As a result our investment in property plant and equipment in 2012 was $83.2m lower than the prior year at $66.7m (2011: $149.9m).

Investment in our Russian plant and equipment accounted for $40.6m (2011: $103.4m) of the Group's capital spend in the year representing 60.3% (2011: 63.8%) of the total for the year. The 2012 cost mainly relates to the testing and commissioning of the plant during the first quarter of the year and additional workover activity in the second half to bring the performance of the initial wells up to the levels of production achieved in testing.

At the end of the year, the carrying value of the Group's oil and gas assets in Russia was $299.6m (2011: $246.2m). Comparing this with the carrying value of the Group's Ukrainian oil and gas assets ($170.3m) is indicative of the scale of our Russian asset and its importance to the Group.

The Group's focus now is to complete the additional well intervention activities at the Koshekhablskoye gas field and expand plant capacity now that it has reached 40 MMcfd.

The remaining portion of the Group's capital expenditure during 2012 was $22.8m (2011: $41.4m) mainly spent in Ukraine.

Our Ukrainian capital investments comprised the drilling of our successful exploration well Zap-04, further in-fill and appraisal drilling at our three producing fields on the Novo-Nikolaevskoye Complex and frac-preparation work at the Rudenkovskoye field.

Exploration and evaluation expenditure

Exploration and evaluation expenditure reduced to $3.8m (2011: $12.8m) in 2012 comprising $2.6m (2011: $0.7m) in Ukraine, $0.7m (2011: $10.6m) in Hungary and $0.5m (2011: $2.2m) in Slovakia. The overall reduction of $9.0m reflects our reduced focus on our Hungarian exploration prospects following some disappointing drilling results in 2011 and early in 2012.

The Pely-02 exploration well in Hungary and the M-172 appraisal well in Ukraine were drilled during the year and the targets proved to be sub-commercial necessitating a combined $5.0m write off of the remaining book value of these assets.

The review of asset carrying values in the statement of financial position concluded that, except for the impairment of our Hungarian assets and the accelerated depreciation of redundant Ukrainian assets, no other impairments were required.

Cash flow from financing activities

Net cash outflow from financing activities in the year was $15.9m (2011: inflow $22.6m) comprising $40.0m of principal repayments (2011: $49.5m receipts) on the loan element of the prepaid swap, off-set by $14.9m (2011: nil) drawn down in the year from the working capital facility provided by Credit Agricole, in addition to the reduction of $9.2m of Restricted cash balances held in our Debt Service Reserve under the prepaid swap (2011: increase $9.8m).

All payments under the short term prepaid swap financing facility completed in December.

No dividends were paid to shareholders in the year (2011: $7.2m).

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 was the Credit Suisse prepaid swap mentioned above.

The repayment of the prepaid swap was structured over an 18 month period and commenced in October 2011. Repayments were straight line at $3.3m per month with additional monthly interest and swap payments based on the Urals Med oil price which totalled $7.1m (2011: $1.7m) (included in interest paid as noted above).

There was a zero coupon rate on the outstanding balance due. However, the overall finance charge to JKX is the cost of the related oil price hedge on 36,000 bbl/month at $94/bbl up to a Urals Med price of $130/bbl. As the Urals Med oil price increased from $94/bbl our effective finance charge and related payment increased; for every $1 increase in the average Urals Med oil price above $94/bbl, the monthly finance charge increased by $36,000.

Full repayment of the prepaid swap occurred in December 2012, which therefore reduced the Group's gross borrowings* to $14.9m (2011: $40.5m) comprised of the balance drawn on the Credit Agricole facility.

*Gross Borrowings is Borrowings gross of unamortised effective interest and arrangement fees.

Total cash

Total cash (cash and cash equivalents plus restricted cash) closed at $12.6m (2011: $28.9m) comprising $12.0m (2011: $19.1m) unrestricted cash and $0.6m (2011: $9.8m) of restricted cash, the majority of which in 2011 was represented by the $9.5m debt service reserve for the prepaid swap facility.

We also have in place a $15.0m working capital facility from Credit Agricole due for renewal in June 2013.

Our Net cash used in investing activities of $70.0m (2011: $164.2m) has been exceeded by our net cash generated from operating activities of $78.5m (2011: $99.0m) during the year, a reversal of the position in 2011.

The overall $16.3m reduction in total cash balances (cash plus restricted cash) is mainly attributable to the $47.1m (2011: $11.7m) of principal and finance payments made under the short term prepaid swap arrangement off-set by the $14.9m (2011: nil) increase in our working capital facility.

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 in February 2013 and the cash requirements of our Russian project reducing, the Group's liquidity position has strengthened significantly.

The level of production and commercial sales at our Russian plant is improving steadily now that we have reached nominal plant capacity.

Our immediate priority is to fund cash generative projects on our existing licences in Ukraine and ensure that our Russian operations become cash positive at the earliest opportunity.

Outlook

In Ukraine we expect the increased realisations from our oil and gas production achieved in 2012 to be maintained through 2013 and current production to improve following the restart in March 2013 of our in-fill and appraisal drilling program, the Rudenkovskoye frac mid-year, the Elizavetovskoye development commencing in 2H 2013 and other production enhancing projects.

In Russia, gas sales from the Koshekhablskoye field will continue to grow as we increase plant capacity above 40 MMcfd.

The proceeds from the convertible bond issued in February 2013 provides sufficient funding for the Group's planned capital investment program for the next 2 years and from which we expect to benefit from increased production thereafter.

Maintaining our low level of gearing continues to provide us with a wide variety of options to maximise our financial flexibility to support our growth objectives.

Cynthia Dubin

Finance Director

Operational review

Operations review - Ukraine

In Ukraine our wholly owned subsidiary Poltava Petroleum Company ('PPC') holds four production licences in the Poltava region of Ukraine (Ignatovskoye, Molchanovskoye, Novo-Nikolaevskoye, Rudenkovskoye). Each production licence contains distinct fields which together form the Novo-Nikolaevskoye Complex. PPC also holds two exploration licences being Zaplavskoye (within the Novo-Nikolaevskoye Complex) and Elizavetovskoye which comprise a total exploration area of 208 sq. km.

2012 update - Ukraine

Our key achievements in Ukraine during the year were:

·; the implementation of the joint production agreement on the Elizavetovskoye Field which led to the re-start of production from the EM-53 well

·; data from this well led to a significant upgrade in the Elizavetovskoye 2P gas reserves to 21.8 Bcf with 0.1 MMbbl condensate (total 3.7 MMboe)

·; approval of the Elizavetovskoye field development plan with first gas anticipated late in 2013

·; the drilling of a successful exploration well (Z-04) in the Zaplavskoye exploration licence encountering highly productive, although short-lived, Visean sandstone reservoirs

·; this was followed up by the acquisition of a 40 sq. km-- 3D seismic dataset extending the total Novo-Nikolaevskoye 3D coverage to 230 sq. km

·; the drilling, testing and/or completing a further 3 appraisal and development wells

·; completing 21 workover operations, including 11 recompletions, 2 well repairs, 1 fishing operation and 7 well abandonments

·; design of an upgrade to the LPG plant to enhance propane recovery for installation in the first half of 2013

·; upgrade of the compressor system to handle lower pressures from the gas production wells

Ukrainian Reserves

Test production of the EM-53 well on the Elizavetovskoye field has enabled us to revise the 2P reserves to 21.8 Bcf of gas with 0.1 MMbbl of condensate, giving a total of 3.7 MMboe. This has been offset to some extent on the Novo-Nikolaevskoye structure where recent drilling has downgraded the potential of the area by 1.5 MMboe leaving remaining 2P reserves of 0.2 MMboe.

Overall, after producing 2.4 MMboe in 2012, remaining Ukraine 2P reserves have increased from 28.5 MMboe to 29.4 MMboe.

Novo-Nikolaevskoye Complex production facilities

2012 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 the Central Production Facility and plans for a modification to enhance the recovery of propane were completed in 2012.

Average LPG sales through 2012 were 52 tonnes per day (2011: 69 tonnes per day).

Outlook

The equipment for the upgrade has been shipped from Canada and commissioning of the new equipment is expected in May 2013.

The additional equipment will deliver an overall 15% increase in LPG production with a commensurate increase in revenue. The total LPG yield at today's average gas composition is expected to increase from approximately 1.94 tonnes/MMcf of gas produced to approximately 2.23 tonnes/MMcf.

Other gas production facilities

A major upgrade to the K-220 compressor took place in 2012 and, together with the newly installed low pressure manifold, increased the facility's flexibility in handling declining reservoir pressure.

Ignatovskoye production licence

2012 update

During 2012 one new well was drilled, four wells worked over and one well was plugged and abandoned on the Ignatovskoye Field:

·; appraisal well IG-135, located on the west flank of the Ignatovskoye structure, was a high-angle well targeting a down-faulted Visean carbonate block. The target reservoir proved tight but a completion in the upper Visean carbonate is flowed at 240 bopd with 1.3 MMcfd gas with a FWHP of 195 psi

·; recompletion of IG-126 as a pilot water injection well in the Ignatovskoye Visean carbonate reservoir. The well is now taking all produced water from the field with the effect expected to be seen in communicating wells by year end. Other water injection schemes are under consideration

·; well IG-133 was recompleted in the V-15 sandstone of the Novo-Nikolaevskoye reservoir to test the limit of that field, but failed to flow. The well was subsequently plugged and abandoned

·; the rod pump in well I-105 was re-installed as part of the regular programme and the well continues to produce at around 45 bopd with 80 bbl water

·; IG-79 was perforated in the Visean Carbonate to test potential in undrained intervals. However, there was no production and the well has been suspended.

Outlook

Wells under consideration for 2013 include a Tournaisian (T-2) Carbonate infill well to test the potential of the mid Tournaisian carbonate and a possible northern extension of the western flank play. Targets will be finalised once the interpretation of the 2012 reprocessing of the 3D seismic dataset is complete.

Reservoir simulation will play an essential part of the preparation for the Ignatovskoye waterflood programme and the second half of the year should see these results being combined with the engineering study for submission as a development plan in early 2014. Water-flooding has the potential to increase ultimate oil recovery significantly.

Ignatovskoye reserves

Production from the Ignatovskoye field of 1.24 MMboe just exceeded the small 1.0 MMboe addition to reserves derived from reservoir modelling. The year-end remaining Ignatovskoye reserves have consequently been revised upwards to 15.1 Bcf of gas and 0.7 MMbbl (total 3.2 MMboe).

Molchanovskoye production licence

2012 update

Molchanovskoye North reservoirs

Work in the Molchanovskoye North reservoirs in 2012 continued to focus on optimising oil recovery from the Devonian sandstone with three workovers performed to ensure maximum oil recovery ahead of gas blow-down from the upper parts of the reservoir and two workovers in the Tournaisian Carbonate:

·; workovers on well M-150 included recompletion to the T2 Carbonate and a recompletion to an overlying Visean sand neither of these yielded significant production volumes

·; following water encroachment, re-completion of the prolific Molchanovskoye well M-166ST higher in the horizon was completed ahead of a planned additional side-track. Even with gas lift, oil production was limited and preparations are being made for the sidetrack

·; Perforations were added higher up in the Devonian sandstone in well M-171 and initial rates of 560 bopd and 3.7 MMcfd were achieved, but declined over the following three months. Gas lift was installed and production has since stabilised

·; M-168 was recompleted to the Tournaisian clastics and tested at a low rate

·; M-164 was recompleted to the Tournaisian Carbonate; however, reservoir pressures encountered indicated that the interval was in good communication with the other carbonate wells in Molchanovskoye North and therefore was depleted. The well will now be abandoned

Outlook

Activity planned for 2013 includes the second horizontal sidetrack on well M-166ST and at least one more in-fill well in the Devonian reservoir to the west of the M-150 location. The bottom hole location will be finalised once the interpretation of the 2012 reprocessing of the 3D seismic dataset is complete.

Integration of reservoir simulation with the revised seismic interpretation will enable planning for a study of water-flooding to proceed in Molchanovskoye North.

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:

·; well M-172 was drilled as an appraisal to the successful M-170 'Wedge Zone' deep Devonian sandstone gas discovery some 500m to the southwest with a TD of 3,203m. Despite encountering the target approximately 200m above the gas water contact in the discovery well, the reservoir was water bearing. This result is attributed to an unseen fault between the wells

·; the well was plugged back and completed in the Visean sandstone reservoir but failed to produce; it was then plugged and abandoned

·; the discovery well M-170 was recompleted to include additional perforations in the less productive zones of the lower Devonian reservoir. Initial flow was 3.9 MMcfd of gas with 304 bcpd.

Reprocessing and re-interpretation of the 3D seismic over the discovery is nearing completion.

Molchanovskoye Main reservoirs

Production from the Molchanovskoye Main field has been from the Main Devonian sandstone unit and has been mostly in the form of a rich condensate. The most prolific well was M-202 but, disappointingly, wells in other fault blocks have not been as productive and this led to a reserves write-down in 2011.

All the wells are now depleted and have been abandoned except M-202, Before abandonment, potentially productive zones in the Tournaisian and Visean reservoirs were perforated but in all cases proved to be unproductive.

Molchanovskoye reserves

Production from the Molchanovskoye fields of 0.6 MMboe exceeded the small 0.2 MMboe addition to reserves derived from reservoir modelling. The year-end remaining Molchanovskoye reserves have consequently been revised to 2.2 Bcf of gas and 0.3 MMbbl (total 0.7 MMboe).

Currently no reserves have been recognised for the Wedge Zone while appraisal is in progress.

Novo-Nikolaevskoye production licence

2012 update

After a successful 2011 drilling campaign, activity in 2012 on the Novo-Nikolaevskoye licence fell back and comprised one new well drilled, one workover and two abandonments:

·; development well NN-78 was drilled to 2,023m and completed in 16 days. The reservoir quality on the southern flank of the Novo-Nikolaevskoye structure proved to be disappointing and initial attempts to flow the V-16 reservoir failed. The second Upper V-15 sand has been recompleted and flowed at 0.4 MMcfd with some condensate

·; recompletion and installation of a beam pump on well NN-76 to lift oil as the gas-oil contact rose. The well is currently on a cycle of intermittent production

·; following depletion, wells NN-72 and NN-77 were plugged and abandoned

The results indicate that while the crest of the structure has turned out to be gas productive, the permeability is such that oil will only flow readily from a few well developed channel sands and that much of the oil rim is consequently unproductive. The sand bodies are relatively thin and do not lend themselves to horizontal drilling.

Novo-Nikolaevskoye reserves

The disappointing results from wells NN-77 and NN-78 have led to a downward revision of the Novo-Nikolaevskoye reserves. Production of 0.4 MMboe combined with the 1.5 MMboe reduction in reserves brought a revision of the year-end remaining Novo-Nikolaevskoye reserves to 1.2 Bcf of gas and 0.03 MMbbl (total 0.2 MMboe).

Rudenkovskoye production licence

2012 update

R-103 Multi-stage Frac

Preparations for the multi-stage frac in the Rudenkovskoye long horizontal well R-103 continued through 2012 with the technical evaluation completed and bids received for the frac operation. The workover to replace the liner involved recovering the 1,200m long uncemented pre-perforated liner and replacing it with a cemented non-perforated liner which will be perforated stage by stage during the frac process.

The preparation and extension of the R-103 well site is virtually complete and included preparation of roads and load area for the frac fleet comprising 14,000hp of pump trucks, full well test spread, coiled tubing services, materials handling and laboratory services. Additional water wells were drilled and four large frac-pits constructed. The complete well-site was 95% ready for operations by the end of 2012.

Outlook

The frac materials order has been placed and includes 1,200 tons of proppant and over 100 tons of other chemicals and consumables. These are being shipped from the USA and China to arrive on location in advance of the scheduled June field operations. Mobilisation of the Schlumberger frac fleet will coincide with materials delivery.

The frac operation itself is scheduled to take at least one month with further time needed for the well to clean up. Meaningful results from the frac should be available in the third quarter 2013.

Other Rudenkovskoye activity included:

·; the recovery of a complicated fish in Rudenkovskoye well R-102 in preparation for testing a shallower Tournaisian interval in the well. The test was ultimately inconclusive and the well remains on batch production.

·; the 2012 reprocessed 3D seismic will be re-interpreted during 2013 as part of a full re-evaluation of the Rudenkovskoye area in anticipation of further drilling and evaluation following the R-103 frac.

Rudenkovskoye reserves

Reserves in the Rudenkovskoye field remain at 122.1 Bcf of gas and 1.2 MMbbl condensate (total 21.6 MMboe) and the areas will be fully reassessed after the results of the R-103 multi-frac and the subsequent drilling programme.

Zaplavskoye exploration licence

 2012 update

The 2010 extension of the Zaplavskoye licence gave PPC access to an area that had been drilled in the 1960s but never put into production. PPC has some 2D seismic over the area and this, together with the database of old wells, enabled it to select a location close to an existing well which permitted good stratigraphic control and reasonable production expectations from the deeper Visean sandstones, also seen further north in the Rudenkovskoye area.

·; the Z-04 well discovered gas in the V-25 and V-26 sandstones with the V-25 appearing to have a better quality, though over-pressured, reservoir. Production testing confirmed this with high initial rates in both reservoirs and, incidentally, a rich condensate giving an increased LPG and C5+ offtake.

·; decline in the V-25 sandstone was rapid with production ceasing after around 10 weeks. The well was recompleted to the deeper reservoir which also started at a high rate but has since declined. The well will now be abandoned.

·; a 40 sq. km 3D seismic survey was completed and processed at the end of 2012 and is now being interpreted.

The over-pressure and short life of the V-25 upper reservoir suggest a small, possibly fault or lithologically bounded, reservoir. The normal pressure and slower decline of the deeper V-26 reservoir suggest a larger reservoir. However the 2D seismic resolution is inadequate and further appraisal drilling will depend on the results of the recently acquired 3D seismic.

Elizavetovskoye exploration licence

The Elizavetovskoye exploration licence is located in the central part of the Dnieper-Donets basin and covers an area of 70 sq. km. It is approximately 45 km from PPC's existing production licences.

Three shut-in production wells on the licence are owned by Ukrgasvydobuvannya, a subsidiary of Naftogaz of Ukraine, the state oil and gas company, and are tied into its East Machevska production facility. Under a Joint Production Agreement ('JPA') PPC is entitled to receive 33.3% of the production from these wells.

2012 update

·; The first of the three legacy wells, East Machevska-53 (EM-53), was brought into production in April, and flowed throughout the remainder of the year at around 2.7 MMcfd (gross) with 15 bpd condensate.

·; The second legacy well, EM-52, has proved to be more difficult to repair and a final decision on whether to proceed has not been made. No decision has been made regarding the third legacy well, EM-205.

·; Plans for upgrading the separation and metering facilities at the Ukrgasvydobuvannya's East Machivske gathering point are under review

Outlook

The data acquired from well EM-53 has given us sufficient confidence to justify a stand-alone development and the final design and work programme will be submitted for approval by the authorities in 2013.

Drilling of the first new well, E-301, and installation of the new PPC operated Elizavetovskoye gas processing facility should commence mid-2013 with production start-up planned for the fourth quarter. PPC will retain 100% of the revenue from all new wells on the field.

Work is already progressing on securing land for the 11 km export line and the hot tap to the nearby gas trunkline was completed in late 2011.

Elizavetovskoye reserves

The 2P reserves for the Elizavetovskoye Field have been upgraded to 21.8 Bcf with 0.1 MMbbl of condensate (total 3.7 MMboe) on the basis of a five well development of the field. Further resources may be added once the field has been in production and additional seismic acquired.

Operations Review - Russia

JKX's wholly owned Russian subsidiary Yuzhgazenergie LLC ('YGE') holds the licence for the redevelopment of the Koshekhablskoye gas field which is located in the southern Russian autonomous Republic of Adygea. The licence covers an area of 34.7 sq. km.

2012 update

Koshekhablskoye Gas Processing Facility

The Koshekhablskoye gas processing facility ('GPF') began test production on March 2012 with gas sales commencing in April.

Upstream issues (see below) have constrained throughput, but the plant has maintained its processing capability despite operating at less than 10% of design capacity. Minor problems have been encountered but these have generally been overcome quickly. Improvements to production allowed the flow rates to rise to around 60% of capacity in the 4th quarter.

All regulatory inspections of the facilities were completed successfully and YGE received its Permit to Operate in early July.

Simulation modelling of the GPF based on actual gas composition and plant operating conditions indicates a significant increase in plant design capacity can be achieved with limited modification. However, this will require additional wells and may require earlier installation of compression than previously planned. Sulphur emissions are being monitored closely and, at present, are comfortably within regulatory requirements. Nevertheless, as production increases, a sulphur recovery process may be considered to reduced output. Timing of these factors is under review ahead of making a firm commitment to proceed.

Koshekhablskoye Production Well Activity

Progress is being made in bringing the existing production wells up to the expected production rates:

·; difficulties were experienced in removing the temporary plug in well-27 following its extended shut-in period since initial work-over and testing in 2009. Differential sticking of the pipe while re-running the completion necessitated a side-track of the well in the reservoir section, this was completed in July and the well was put into production in August prior to stimulation. Acetic acid stimulation doubled its production rate to more than 9 MMcfd but it has since declined. A hydrochloric acid stimulation has proved to be very successful with flow rates exceeding 21 MMcfd and good wellhead pressure. The well has been choked back to 16 MMcfd to minimise corrosion in the tubing.

·; well-20 started producing but at a reduced rate due to a downhole restriction. The blockage was cleared using coiled tubing and acetic acid. The well was then stimulated successfully using a larger acetic acid squeeze and production rose to at around 15 MMcfd before declining once again. The subsequent hydrochloric acid stimulation was even more successful and resulted in initial production rates reaching 15.9 MMcfd with a flowing WHP of 4,745 psi through a 25/64 inch choke.

·; earlier testing in well-25 had also indicated a downhole blockage, probably mechanical. The Geostream rig carried out a successful side-track in late 2012 and the well entered production at 12 MMcfd before plugging off. The coiled tubing unit has successfully cleared the obstruction and production is now running at around 13 MMcfd.

·; coiled tubing was also run in well-05 and, although good progress was made inside the tubing, it became evident that the annulus was blocked with sediment and/or corrosion products and there was a leak in the tubing. The Geostream rig is now preparing an intervention to recover the tubing and drill a sidetrack to the Oxfordian reservoir.

The hydrochloric acid stimulation programme with the coiled tubing unit has opened up the wells sufficiently to permit them to produce near their optimum rates. Successful completion of the well-05 workover should then provide sufficient flexibility to maintain production above normal plant capacity of 40 MMcfd.

Koshekhablskoye Field Exploration and Appraisal

Our licence in Koshekhablskoye requires that we drill or workover two Callovian wells and carry out a reserves determination on both the Oxfordian and Callovian reservoirs. YGE has continued to maintain a regular dialogue with Rosnedra, the licensing authority, and has recently agreed with them to defer completion of this licence commitment to July 2014.

This will entail re-entering and sidetracking well-09 to re-drill the full Callovian reservoir sequence and, if successful, testing of the Callovian V unit.

Callovian well 22 remains suspended while equipment to repair the casing is sourced.

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 well-22 and, when available, the data will be incorporated into the reserves assessment due in 2014.

Production from the Koshekhablskoye field in 2012 was 0.4 MMboe and there has been an upward revision of 2.9 MMboe. The year-end remaining reserves have consequently been revised to 379.5 Bcf of gas and 0.6 MMbbl of condensate (total 63.9 MMboe).

Georgievskoye Exploration Licence

YGE was awarded the 170.7 sq. km Georgievskoye exploration licence in May. The largest part of the licence lies adjacent to, and immediately south of, the Koshekhablskoye production licence but a significant part of it also runs to the northwest of the Koshekhablskoye field as well as covering the west and east flanks of the field.

The whole of the mapped field area is now secured under licences held by YGE.

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.

There is also an additional lead in the south of the block, beyond the existing 3D seismic coverage, with estimated P50 unrisked resources of 30 Bcf.

Outlook

The 2013 work programme will entail recovery, reprocessing and interpretation of all existing 2D seismic in preparation for further seismic acquisition in 2014.

Operations Review - Hungary

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

JKX holds 50% equity in the northern Pannonian Basin Hernád licences and Gorbehaza Mining Plot in a joint venture with the operator, Hungarian Horizon Energy ('HHE').

2012 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 and averaged 60 bopd with 380 bwpd through December before liquid loading stopped production just before the year-end. Attempts were made to clear the well with nitrogen lift and recommence production but the 2013 forecast is uncertain

·; Well Hn-2 was in production until August averaging 1.5 MMcfd with 35 bcpd and over 100 bwpd when water breakthrough killed the well. It was restarted in February 2013 and producing at around 0.5 MMcfd with almost 800 bwpd.

·; The Gh-1 well production was planned to resume with pressure support from a small compressor, but on restarting the well flowed insufficient gas to lift the produced water. The well is now being permitted as a water disposal facility.

Outlook

Well Hn-9 is planned as an infill development well for the first half of 2013. The target will be the Fractured Miocene Oil reservoir. The secondary target is potential attic gas within the Pannonian Pegasus Sand interval

Hajdunanas and Gorbehaza Reserves

Average gross production in 2012 was 432 boepd (JKX net: 216 boepd) comprising 2.1 MMcfd of gas and 87.2 bpd of oil and condensate, a 1.5% decrease on the average for 2011.

The continuing water influx in the main Pannonian gas reservoirs during the year has further reduced the reserves and field life which have only been partially offset the success of the Miocene oil reservoir test.

Remaining gross reserves in the field are now 0.8 Bcf and 0.2 MMbbl (JKX net 0.2 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 the period leaving a total of 1,827 sq. km; the Hernad II licence area is unchanged at 2,507 sq. km. Reprocessing of the 2011 Jaszsag area 3D seismic data has been completed.

Outlook

The Operator is reinterpreting the dataset and incorporating results from the 2012 Pely-2 well. The 3D seismic has been reprocessed and a revised interpretation for the area is nearing completion with a shallow prospect, Tisvaszvari-15, already identified for drilling in 2013. Following the full interpretation process a prospect inventory will be established.

Sarkad I Mining Plot (JKX 25%)

In March 2009, JKX farmed-in for a 25% interest in a 15.6 sq. km area of the Veszto exploration licence held by HHE in the east Hungarian Pannonian Basin. This was subsequently converted to a 53 sq. km (Mining Plot) Development Licence in 2012.

 JKX retains its 25% interest in the 15.6 sq. km farm-in area around the Nyekpuszta-2 gas condensate discovery well.

The Operator is continuing the evaluation of appraisal locations and an appraisal well is under consideration for the second half of 2013.

Turkeve IV Mining Plot (JKX 50%)

JKX entered into a farm-in agreement to participate in the drilling of up to seven shallow wells located in the Turkeve area of north east Hungary in late 2010. Under the terms of the agreement, JKX funded 66.67% of the drilling and completion costs to earn 50% of future mining plots formed to develop discoveries.

Well Ny-7 made asignificant gas discovery in 2011 but the proportion of CO2 (25%) requires a more complex treatment plant. The operator continues to evaluate treatment and development options but nothing has been settled and production is unlikely before the second half of 2013.

The Turkeve IV Mining Plot of 10 sq. km, has been approved for the productive area around the Ny-7 well.

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.

During 2012:

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

·; an extensive aero-gravity survey was acquired during the third quarter of 2012

·; the data have now been processed and the results will be incorporated into the well location and we are planning for a spud date in late 2013 or 2014.

Operations Review - Bulgaria

Golitza Licences (JKX 40% and operator)

The B1 Golitza licence, in which JKX held a 40% interest, expired in March 2012.

Provadia licence (JKX 18%)

JKX has 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 is complete and has revealed little of interest. JKX has initiated its withdrawal from the licence which is expected to complete during Q2 2013.

Principal risks and uncertainties

2012 update

The principal risks facing the Group have not changed significantly from those detailed in the 2011 Annual Report. However our overall assessment of those risks has changed in 2012 as follows:

·; liquidity risks have declined now that we are fully funded for our planned development programme in Russia and Ukraine following the successful issue of the $40m convertible bond in February 2013.

·; the risk rating applicable to operating costs and capital expenditure has increased due to overall industry cost pressures relating to increases in labour and capital equipment costs, together with increased well remediation activity at our Russian operations and on our three mature fields in Ukraine; we closely monitor and control operating and capital costs across all our operations

·; the foreign exchange risk rating has declined following the devaluation in the Ukrainian Hyrvna. Additionally, gas sales revenues in Russia are now partially mitigating the exposure of our local cost to the Rouble/$ fluctuations.

Whilst recent changes implemented in the Ukrainian production tax regime and the Russian government's announcement stating their intentions for Mineral Extraction Tax rates and gas price increases through 2015 provide us with a welcome measure of stability, we consider it prudent to leave our risk rating for Country Exposure, and the related Tax legislation risks, unchanged.

Our assessment of the most significant risks and uncertainties which could impact long-term performance is detailed in the Annual Report. The principal risks set out therein are not set out 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

Consolidated statement of financial position

as at 31 December

Consolidated statement of changes in equity

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 2012 (the 'financial statements'). 

The 2012 Annual Report was approved by the Board of Directors on 8 April 2013, and will be mailed to shareholders in April 2013. 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 2011 have been delivered to the Registrar of Companies. The Auditors' report on the full financial statements for the year to 31 December 2011 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 2011 Annual Report. A full list of accounting policies will be presented in the 2012 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, appraisal, development and production of oil and gas reserves. Accordingly the reportable operating segments are determined by the geographical location of the assets.

There are five reportable operating segments which are based on the internal reports provided to the Chief Operating Decision Maker. The Ukraine, Russia and Hungary are involved with production and exploration; the 'Rest of World' is involved in exploration and development 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 the World' segment comprises operations in Bulgaria and Slovakia. 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. Segment assets consist primarily of property, plant and equipment, inventories and receivables. Capital expenditures comprise additions to property, plant and equipment.

There is 1 (2011: 2) 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 $2.5m (2011: $3.2m), at a weighted average interest rate of 25.2 per cent (2011: 25.2 per cent).

Oil and gas fields in Ukraine and Russia include $9.1m and nil respectively relating to items under construction (2011: $14.3m and $246.2m). 

Exceptional item - 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, certain oil and gas assets have become obsolete and therefore their carrying value has been written off. A one-off accelerated depreciation charge of $30.7m has been recognised in the consolidated income statement during the year 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.

The write off of exploration and evaluation costs comprises exploration and drilling costs of $3.6m (2011: nil) in respect of the M-172 well in Ukraine, $1.2m of drilling costs (2011: nil) in respect of the Pely-2 well in Hungary, exploration costs of $0.2m (2011: $6.7m) in respect of our Turkeve licence in Hungary and $0.2m (2011: nil) in respect of cost recoveries against Bulgarian exploration costs previously written off.

The total write off of unsuccessful exploration and evaluation costs of $4.9m (2011: $12.9m) has been 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. In 2012 indicators of impairment were noted in respect of our Hungarian assets (see note 4 (d)). No other impairment triggers were noted and no other impairment charges have been recognised.

Following this review in 2011 impairment triggers were noted in relation to Yuzhgazenergie (YGE) in Russia. See note 4(d) for the results of the 2011 YGE impairment test and consideration of the carrying value at 31 December 2012.

4. (d) Exceptional item - 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 have 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 has been 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 contains these two wells and which is held by HHE North Kft (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 has been undertaken in US$ being the functional currency of our Hungarian operations. 

The key assumptions used in the impairment testing 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 is dependent upon judgment used in determining such assumptions.

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

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

Yuzhgazenergie (YGE), Russia - 2011 Disclosures

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.

The anticipated cost of the development plan has continued to increase in 2011 and although first gas sales from the project are imminent they are delayed from when originally planned and from the assumptions used for the 2010 impairment review.

In 2011, the anticipated convergence of Adygean gas prices to net back European levels was forecast to be later than assumed in the prior year's impairment review. Historically gas prices in the Adygea Region are higher than the average gas price across all regions in Russia.

In 2011 the Company considered that the delay to production start-up and the resulting additional capital expenditure incurred to constitute an impairment trigger. Accordingly an impairment test was undertaken in 2011.

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 - 2011 Disclosures

The key assumptions used in the 2011 impairment testing were:

·; Production profiles: these were based on the latest available information provided by independent reserve engineers, Senergy (GB) Limited, such information included 2P reserves of 61.2 MMboe. No value was attributed to the unconfirmed expectations of the 3P and contingent resources which may be relevant to any valuation by a market participant.

·; 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 2012 these were based on the gas sales agreement that the Company had negotiated with Kubangazifikatziya for the forecast gas production in 2012. 

·; Gas prices: for 2013 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 assumed net-back convergence occurring in 2020 and applied the Russian government's stated intention to increase gas sector tariffs by 15% on 1 July 2012 and by 15% per annum in 2013 and 2014 to calculate expected future Russian gas prices in those years, and by 15% thereafter to achieve European net-back convergence in 2020. This timing of convergence is consistent with current views expressed by many market commentators.

·; Gas prices: the gas price was assumed to increase in line with forecast Rouble inflation after 2020 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 13.0%. This was based on a Capital Asset Pricing Model analysis consistent with that used in previous impairment reviews.

Based on the key assumptions set out above YGE's recoverable amount exceeds its carrying value by $35m in 2011. In 2011 it was concluded that 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 2011 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:

2011 Sensitivity Analysis

2012 update

For purposes of testing for impairment of YGE's non-current assets in 2012, we have adopted a similar process to that used in previous periods. Having taken account of developments since the last test for impairment, based on the assessment of fair value less costs to sell, the recoverable amount exceeds the carrying value by approximately US$29m (9.1 per cent) (2011: $35m, 12.4 per cent) and no impairment trigger has been noted. However it should be noted that the estimate of the recoverable amount uses a discounted cash flow (DCF) methodology which is highly sensitive to changes in the key assumptions of future Russian gas prices and related production taxes, both of which are under the direct control of the Russian government.

As 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. The Company's estimates also reflect the Russian government's recent confirmation of gas production tax rates through to 2015 and an inflationary increase has been applied thereafter.

5. Borrowings

Pre-paid swap

The Pre-paid swap related to a term loan which the Group entered into on 14 June 2011 with Credit Suisse International. The transaction which secured $50m for capital expenditure and other purposes is repayable over an 18 month schedule commencing in September 2011, concluding with a final payment in November 2012. There was a zero coupon rate on the outstanding balance however under the transaction the Group hedged forward sales of oil.

The pre-paid swap was secured over the shares of all those Group subsidiaries which own, control or have an interest in the Group's oil and gas licences.

All obligations under the pre-paid swap concluded with a final payment to Credit Suisse in December 2012.

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 2012 and is available until 30 June 2013 (2011: 30 June 2012). 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.

6. Cost of sales

7. Taxation

Factors that affect the total tax charge

The total tax charge for the year of $13.0m (2011: $22.9m) is higher (2011: higher) than the average rate of UK corporation tax of 24.5% (2011: 26.5%). The differences are explained below:

The current tax charged in the year 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 (note 6).

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.

The UK Finance Act 2012 reduced the main rate of corporation tax from 26% to 24% from 1 April 2012 and to 23% from 1 April 2013. A further reduction to 21% from 1 April 2014 was also announced but not substantively enacted at the reporting date. The impact of the rate reduction is not expected to have a material impact on provided and unprovided UK deferred taxation.

In December 2010 a new Ukrainian tax rate was introduced. The new corporation tax rate in the Ukraine for 2012 was 21%, the expected corporation tax rates in 2013 and 2014 are 19% and 16% respectively.

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. 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 April 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 additional production related taxes for the period from May 2007 to March 2010 is remote on the basis of tax audits completed, the related legal position and the three year statute of limitation. The Group would exhaustively challenge the payment of any further production related taxes (over and above those it has already paid) for the period through 31 December 2010. Given the lack of clarity over the legal position together with arguments that the Group has to defend its position, the Group considers that no payments are likely to be made in the next 12 months.

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 following data:

Earnings before exceptional item in 2012 of $24,701,965 (2011: $59,137,000) is calculated from the 2012 loss of $11,335,000 (2011 earnings: $59,137,000) and adding back exceptional items of $45,816,000 (2011: nil) less the related deferred tax on the exceptional items of $9,779,000 (2011: nil).

In accordance with IAS 33 (Earnings per share) the effects of anti-dilutive potential have not been included when calculating dilutive loss per share for the year end 31 December 2012. There were 3,499,863 (2011: 2,759,824) outstanding share options at 31 December 2012, of which 1,247,010 (2011: 766,518) had a potentially dilutive effect.

9. Reconciliation of profit from operations to net cash inflow from operations