Half Yearly Report

FOR IMMEDIATE RELEASE 31 AUGUST 2011

JKX Oil & Gas plc

("JKX" or the "Company")

HALF-YEARLY RESULTS

 FOR THE SIX MONTHS ENDED 30 JUNE 2011

Key Financials

·; Revenue up 3% to $107.8m (2010: $104.5m)

·; Production based taxes increase to $33.0m (2010: $2.6m)

·; Operating costs reduced by 27% to $9.0m (2010: $12.3m)

·; Profit before tax: $32.7m (2010: $49.1m)

·; Earnings per share: 14.0 cents (2010: 20.7 cents)

·; Operating cash flow: $58.9m (2010: $67.2m)

·; Capital expenditure up 48% to $101.0m (2010: $68.3m)

·; Cash resources: $63.6m (2010: $107.2m)

·; Total borrowings: $58.9m (2010: Nil)

·; Interim dividend passed

Operational Highlights

·; Average production of 9,476 boepd (2010: 11,689 boepd)

·; LPG project in Ukraine completed on schedule and on budget

·; Koshekhablskoye construction project nearing completion

·; Progress made on the Group's exploration programmes in Ukraine and Hungary

Outlook

·; Russian production now scheduled to come on-stream by year-end

·; Testing of initial Callovian appraisal well in Russia

·; On-going Ukrainian development drilling with exploration drilling on Zaplavskoye licence extension

·; Contract award of Rudenkovskoye multi-frac operation in Ukraine

·; Appraisal drilling on Tiszavasvari gas condensate discovery in Hungary

JKX Chief Executive, Dr Paul Davies, commented:

"We have delivered a solid operating performance in the first half of the year while striving to complete our large Russian redevelopment project. Despite schedule delays, we anticipate production in Russia commencing by the year-end. We have achieved a key milestone in starting-up LPG production in Ukraine on schedule and on budget. Higher taxation in Ukraine this year and increased Russian project costs are impacting cash flow and the Board believes it is prudent to forgo a dividend payment at the interim stage.

We expect our earnings for the year to be in line with expectations, and remain committed to delivering long term value for our shareholders."

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CHAIRMAN'S STATEMENT

Strategy

The Group strategy is to grow our established operator position in eastern and central Europe and your Company has made significant progress in the period towards achieving its 2011 goals. Ukraine remains our key market with improving prospects for growth. The Russian independent gas market continues to develop and we remain confident that our early participation will lead to further growth opportunities. However, we are experiencing schedule delays on our key project in Russia which we now expect to come on-stream by the year-end.

Performance

In the first half of 2011 your Company's fortunes were, as in the past, driven by operations in Ukraine which continue to be a stable base for the Group despite the significant impact of the new production taxes and some fall off in volumes produced. We are however experiencing yet further delays in completing the Russian project which is having a significant effect on our cash position. During the period we arranged borrowings of $65m of which approximately $59m were drawn at the end of the period. We have re-scheduled completion of the Russian project for the end of 2011. Your Company's development drilling programme in Ukraine is proceeding on schedule and the key milestone of starting up LPG production was achieved on time and on budget. We have also benefited from higher international oil prices and strengthening of local gas prices. Progress has been made on the Company's exploration programmes with drilling success in Ukraine and a further gas find in Hungary. However, production in Hungary has not grown in line with our expectations.

Dividend

In my 2010 Annual Statement, I drew attention to the impact on available cash flow of increased taxation in Ukraine in 2011 and the delay in start-up of the Russian project. Clearly, the change in Ukrainian tax levels means that 2011 is the year in which our profits are re-based as they bear this significant additional cost. We are also facing additional site construction costs in Russia as we are nearing project completion. In light of these factors, the Board has considered it prudent to forego an interim dividend. We will review the payment of a final dividend in the circumstances prevailing at the year end.

Board

As already announced, Bruce Burrows is retiring as Finance Director by the end of the year. I would like to take this opportunity to thank him and wish him well for the future. The search for his successor is well underway and we expect to make a further announcement in due course.

Your Board supports the longer term aspirations of Lord Davies's report regarding gender diversity on appointment of directors to boards. We will continue to search for the highest quality people with the most appropriate experience for the requirements of the business, be they men or women.

Outlook

The Company is committed to bringing its Russian project on-stream by the year-end. This will lift our Group production levels significantly and also ease the pressure on capital funding going into 2012. The development drilling programme in Ukraine is on-going and we anticipate maintaining production at current levels through year end. Work-over operations are being planned in Hungary to improve production levels together with an appraisal well on the Tiszavasvari gas condensate discovery. Finally, on our Slovakian licence, a drilling location has been identified and we are planning to drill an exploration well.

We continue to seek opportunities for growth whether by acquisition or by organic development in our core central and east European areas, with particular emphasis on Ukraine.

CHIEF EXECUTIVE'S STATEMENT

In the period under review we continued to focus on recovering production in Ukraine, although this was partially offset by a reduction in Hungarian production from the Hajdunanas and Gorbehaza fields. Oil realisations in the period improved by 48% to $97.92/bbl (2010: $65.97/bbl) capitalising on the rise in international oil prices. Gas realisations in the period improved by 17% to $8.68/Mcf (2010: $7.41/Mcf) reflecting the rise in average price of Russian gas deliveries to Europe.

Ukraine

Development activity continued on schedule in the period with four development wells drilled and workovers completed on a further thirteen wells. A key achievement in the period was the completion of the LPG facility which was on schedule and on budget with initiation of sales at mid-year. Production is currently averaging 70 tonnes per day, with an average sales price in excess of $900 per tonne. The development of the Rudenkovskoye field continues as we complete the geological and geotechnical studies as well as the design of the multi-stage frac for the long 1 km horizontal section of the R-103 well. Tenders have been issued to a number of international contractors for the frac operation, and early responses indicate that the operation will be carried out in the spring of 2012 due to the extended time required to mobilise the large amount of equipment required into Ukraine.

Russia

The redevelopment of the Koshekhalbskoye gas field in southern Russia is in its final phases of testing and commissioning. Well 25, the third of the initial three well workovers is currently under test and initial results indicate that well performance will be similar to that achieved by Well 27.

Completion of hook-up and testing of the processing facilities and on-site utilities is well advanced but we have experienced delays in some equipment deliveries and completion of certain installation activities which has caused overall schedule slippage. We have mobilised additional contractor manpower and equipment to mitigate this and the Company is in discussions with the lead contractor to minimise additional costs and further delay to the completion of the project. I am confident that these additional costs are contained and the revised schedule of first gas by the end of the year is realistic.

Current & Future Activity

The next 12 months will see a continuation of drilling activity on the Poltava licences in Ukraine utilising the Skytop N-75 rig supported by the TW-100 workover rig. This will entail the completion of well IG-137(Bis), the side-tracking of the horizontal Devonian sandstone development well M-166 in the Molchanovskoye North field, a further development well in the Novo-Nikolaevskoye field, the first exploration well in the northern Zaplavskoye licence extension and, potentially, an appraisal well on the western flank of the Ignatovskoye field. Continuation of the development programme on the deep tight gas on the Rudenkovskoye field is of great significance with the planned multistage fraccing of the long horizontal well R-103. The extended contractor mobilisation required has deferred the frac operation to early spring.

Once the Koshekhablskoye field in Russia has come on-stream attention thereafter will switch to the Callovian wells 09 and 22, not only as support for current production, but as a potential starting point for the development of the Callovian reservoir.

In Hungary, the highest priority is to restore production in the Hajdunanas Field. The second well to appraise the Tiszavasvari gas condensate discovery is being considered, alongside further prospect definition from the new Hernad licence seismic data.

The strategy of focusing the Company's exploration efforts in eastern and central Europe will continue. The Company has established gas production in Hungary and is pursuing its exploration programme in the area with vigour. We continue to seek development opportunities in our core areas particularly in Ukraine.

OPERATIONAL REVIEW

Ukraine

NovoNikolaevskoye Licences

Production

Average production in the first half was 8,833 boepd comprising 39.2 MMcfd of gas and 2,298 bpd of oil and condensate, an 18% decrease on the average for the first half of 2010. Despite a compressor failure in May, production increased in the second quarter following the impact of the Molchanovskoye "Wedge Zone" exploration well M-170 and modifications to the compressor system. The "Wedge Zone", a downthrown tilted fault block, separates the Molchanovskoye North and Molchanovskoye Main fields. Production in the second quarter was approximately 9,400 boepd but is settling back to an average of around 8,800 boepd during the third quarter of 2011.

Development Drilling & Workover Activity

In the first half of the year, activity at our wholly-owned subsidiary Poltava Petroleum Company ("PPC") focused on oil and gas production in the Novo-Nikolaevskoye complex with infill wells on the Molchanovskoye North field and step by step development of the Novo-Nikolaevskoye field. In parallel, optimisation of the flowline network at the complex is making a useful contribution to production rates.

During the first half of the year PPC worked-over 13 wells and completed four development wells in the Poltava licences using its Skytop and TW-100 rigs.

·; Development well M-169 was spudded in 2010 and was completed in March 2011 as a 600m long horizontal well in the Molchanovskoye North Devonian reservoir. It was designed to replace both wells M-151 and M-152 and has been set higher in the reservoir. Optimisation of the flowlines enabled the gas rate to be increased to 8.1 MMcfd with 260 bcpd.

·; Development well M-171 was drilled and completed in 29 days with a short (150m) horizontal section in the Devonian sandstone. It is located in the partially depleted southernmost fault block of the Molchanovskoye North field and is now in production after testing at 309 bopd with 1.8 MMcfd gas.

·; Development well N-75 was drilled and completed in the Novo-Nikolaevskoye field in the Visean V-16 reservoir, some 260m to the west of the surface location. Following the replacement of faulty tubing, the well was recompleted and production has increased steadily from an initial rate of less than 1 MMcfd to 1.53 MMcfd and 4 bcpd in its most recent test.

·; Development well N-76 targeted the same reservoir some 670m to the east of its surface location. Both wells were drilled from the Novo-Nikolaevskoye wellhead cluster. Well N-76 came on-stream at a modest initial rate and slowly increased to its current rate of 1.34 MMcfd with 80 bopd.

The development wells were drilled and completed by PPC's Skytop rig which has now moved to well IG-137(Bis) which is a Tournasian sandstone development well in the Ignatovskoye field and is currently awaiting completion.

Other significant activity during the first half of the year involved PPC's TW-100 rig which completed four workover/recompletion operations, two successful fishing operations and abandoned seven wells that are no longer capable of production. The workover and recompletion highlights were:

·; The recovery of a complicated fish in well I-106 on the Ignatovskoye field which permitted a recompletion in the Devonian sandstone, with the well finally testing at 6.2 MMcfd with 53 bcpd.

·; Workover of well I-128 on the Ignatovskoye field involving successful water shut-off and gas lift installation, enabling oil production from the well to almost double to 228 bopd with 0.4 MMcfd gas.

·; Recompletion of well N-73 in the Novo-Nikolaevskoye field to the Visean V-15 reservoir following water influx in the V-16 reservoir. Current production from well N-73 is 1.7 MMcfd with 15 bcpd.

·; Recompletion of well M-152 in the Molchanovskoye North Devonian reservoir for water shut-off was unsuccessful but has subsequently been replaced by well M-169.

·; Replacement of the 3 ½" tubing in well R-103 in the Rudenkovskoye Devonian reservoir by 2 7/8" tubing to overcome liquids loading. The well is now shut-in awaiting fracture treatment.

·; Replacement of the rod pumping system in well I-105 on the Ignatovskoye field by a surface driven cavity pump. Installation of the pump and surface motor is in progress.

Molchanovskoye Licence Exploration Activities - "Wedge Zone"

Exploration well M-170 was drilled during the period and encountered a 116m gas column with a net pay of 54m in a lower Devonian sandstone beneath the main uppermost Devonian reservoir which is water bearing.

Consequently a 35m zone was perforated and, after an initial flow rate of 17.1 MMcfd, production has settled at around 2.8 MMcfd with 80 bcpd.

This zone is approximately 400m deeper than any gas or oil found to date in the adjacent Molchanovskoye fields and remapping is now underway to estimate the extent of this reservoir.

A second well in the block is planned for early in 2012 with locations in other fault blocks being identified for later 2012 drilling.

Liquefied Petroleum Gas (LPG) Production Facilities

The highlight of the year to date for PPC has been the start-up of production and initiation of sales of liquefied petroleum gas (LPG) at the central production facility. The process extracts propane and butane from the export gas stream for sale as LPG.

This reduces the gas available for export however the value of the LPG revenue stream enhances PPC's economic performance by increasing overall realisations from its gas production.

The LPG processing plant was designed and built in Canada and mobilised to Ukraine during the second quarter of this year. Storage and loading facilities were constructed in Ukraine with installation completed in June.

Modifications to the existing gas processing facilities were undertaken during the annual facility maintenance shut-down in May.

Following commissioning and testing, LPG production commenced on 4th July and commercial shipments are being dispatched daily by road tanker.

LPG production is planned to reach approximately 80 tonnes per day with daily off-take contracted to pre-qualified wholesale distribution companies.

Other Gas Production Activities

The K-300 compressor provides support for the lower pressure gas wells and makes an increasingly significant contribution to production as natural reservoir pressures decline.

An unexpected failure of its gas engine crankshaft in May reduced PPC's overall production by nearly 20% over an 18-day period. A replacement crankshaft was available and was installed during the May field shut-down which coincided with a planned upgrade to the unit and has resulted in an increase of almost 10% to PPC's field production.

Elizavetovskoye Exploration Licence

Following resolution of the status of the Elizavetovskoye licence in 2010, preparations are underway for the development of the remaining reserves in this field. The hot tap to the nearby gas trunkline was successfully installed during the first half of the year as a pre-requisite to development of the field in 2012. Equipment requirements and well design are currently being finalised.

Zaplavskoye Exploration Licence

The Zaplavskoye licence extension included an area between the Novo-Nikolaevskoye and Ignatovskoye licences where existing seismic data indicates potential drilling targets and extends the northern flank of the Novo-Nikolaevskoye field. A well location has been identified for drilling, adjacent to an abandoned gas discovery. Additional 3D seismic is planned for 2012.

Russia

Koshekhablskoye Licence

Our wholly owned subsidiary, Yuzhgazenergie ("YGE"), is redeveloping the Koshekhablskoye Field in southern Russia. Initial well workover operations are almost complete and progress continues with the installation of the new gas processing facility (GPF). Site construction is nearing completion and commissioning of individual components has commenced. First gas is expected by the end of the year.

Development Drilling & Workover Activity

The Geostream rig re-entered Well-25 on the northern flank of the field and recovered the remainder of the tubing. Drilling of the 270m sidetrack into the limestone reservoir kicked-off at 5,490m and reached the planned TD of 5,763m. The completion was run and preparations were being made to test the well when the coiled tubing parted in the well bore. The tubing has now been recovered although additional wireline work is required to enable the well to be fully completed. Preliminary test data indicates that the well has similar properties to Well-27.

Wells 20, 25 & 27 are expected to provide the initial production for start-up with a combined flow potential in excess of the designed GPF capacity of 40 MMcfd. Additional wells will be worked over as required to maintain design capacity throughput.

Preparations for the sidetrack of the Callovian Well-09 and the deepening of Well-22 to the Callovian sandstone reservoir were completed in the period by smaller capacity rigs. The Geostream rig is scheduled to return to complete operations on these wells prior to testing.

Facilities Construction

GPF plant

The main components of the process plant were delivered from Sharjah to the Russian port of Novorossiysk, some 300km from the field, and transported to the site during the first quarter.

Installation is now complete with all major components in place and hook-up in progress. Cabling and piping connections are well underway and localised commissioning has started.

Completion of the ground works for the drainage and firewater systems began after the spring thaw but operations have been hampered by unseasonably heavy rain in June and July. Installation and construction of locally sourced equipment and buildings is virtually complete with the power centre scheduled to start-up in September using imported gas.

Delays have been experienced in some equipment deliveries and completion of certain installation activities which has caused some schedule slippage. We have mobilised additional contractor manpower and equipment to reduce the impact of this but to date this has only been partially achieved. The Company is in discussions with the lead contractor to minimise the additional costs and delay to completion of the project and the revised schedule now anticipates first gas before the end of the year.

Hungary

Hajdunanas Field

Production

The Hajdunanas and Gorbehaza fields produce from three wells to a single separator and then via a 14.5 km export line to an existing facility for input to the Hungarian gas pipeline system. Production has been hampered in the period by some water influx but until recently the operator has been able to maintain gross rates at the contracted delivery level.

Average gross production in the first half was 1,285 boepd (JKX net: 643 boepd) comprising 6.7 MMcfd of gas and 174 bpd of condensate, a 31% decrease on the average for the first half of 2010.

Recently, production has fallen to around 3.5 MMcfd with 70 bcpd (~325 boepd net to JKX) due to water influx. Well Hn-1 has been shut-in and Hn-2 has seen an increase in water. Remedial action, including workovers and additional drilling, is being planned to restore production to around 1,300 boepd and to increase oil production from these wells.

Exploration & Appraisal

Hernad Licences

JKX holds a 50% equity interest in two northern Pannonian Basin Hernad licences (Hernad I and Hernad II).

The Tiszavasvari-6 well was tested in January after encountering a 300m gross reservoir interval with excellent gas shows below 2,580m. Three reservoir intervals were tested with a maximum rate of 1.5 MMcfd being recorded. The well has been suspended in anticipation of a possible reservoir stimulation programme.

A larger tilted fault block structure with amplitude supported Lower Pannonian reservoir intervals lies updip from the first structure and appraisal drilling is being considered.

A further 200 sq km 3D seismic data was acquired in the Jaszsag area to the south of the Hernad II licence and preliminary processing of the data is now complete.

Veszto Licence

JKX holds a 25% equity interest in a 15.6 sq km part of the Veszto exploration licence. A further well is planned once the Mining Plot for the area has been issued. In addition to the testing and completion of the Nyekpuszta-5 well, activity under consideration for 2012 includes evaluation of a similar prospect within the proposed Mining Plot in which JKX has an option to participate.

Turkeve Licence

JKX entered into a farm-in agreement for drilling of up to seven shallow wells located in the Turkeve area of north east Hungary. 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, and funding 75% of any pipeline connection costs. Six wells were drilled during the period, but only one encountered gas, flowing at 2.0 MMcfd through a 6mm choke with a WHP of 1,680 psi, but with more than 25% of carbon dioxide. The operator is evaluating treatment and development options with a view to bringing the field into production.

Bulgaria

Exploration

B and B1 Golitza licences

JKX holds a 40% interest in the B and B1 Golitza licences and is the operator. The lack of success in the 2010 drilling programme was disappointing. However, JKX and its co-venturers continue to integrate the information from these wells with the 3D seismic data to high-grade further exploration targets within the Avren Formation.

Provadia licence

JKX has a 16% carried interest in the 1,787 sq km Provadia licence operated by Overgas. A 380 km 2D seismic survey is being planned.

Slovakia

Exploration

Svidnik, Medzilaborce and Snina Licences

JKX holds a 25% equity interest in the Svidnik, Medzilaborce and Snina exploration licences in the Carpathian fold belt in north east Slovakia. Following the 2010 acquisition of a further 150km of 2D seismic data to firm up leads identified in the 2008/2009 surveys, several structures have been refined in the vicinity of the Smilno discovery well in the Svidnik licence. A drilling location has been selected and planning is underway to drill an exploration well. Further regional seismic data acquisition of 300 km is currently underway over the Medzilaborce and Snina licence.

Financial Review

Group Revenue was marginally higher during the period at $107.8m (2010: $104.5m) mainly due to the significantly higher oil and gas prices realised in the period. Group operating profit for the period however was 32% lower at $32.9m (2010: $48.6m) primarily as a result of the introduction of the new tax code in Ukraine which we announced in January 2011.

Revenue

Group revenues were driven by higher commodity prices which were counteracted by lower sales volume. Average sales volume in the period was a combined 9,440 boepd (2010: 11,072 boepd), with 93% (8,821 boepd) sold in Ukraine, and the remaining 7% (619 boepd) in Hungary. The 15% fall in combined volume sold was wholly attributable to reduced oil sales volumes. This reduction was more than offset by the 17% increase in average gas price realised of $8.68/Mcf (2010: $7.41/Mcf), and the 48% increase in average oil price realised of $97.92/bbl (2010: $65.97/bbl). These price levels have increased further into the third quarter of the year with the current gas price in Ukraine being above $10/Mcf and the current oil price realised in Ukraine above $110/bbl.

The resultant total group revenue for the period was $107.8m (2010: $104.5m).

Profit From Operations

Total costs of sales for the period (excluding exploration cost write offs) were up significantly at $58.3m (2010: $33.4m). As announced, this increase is entirely driven by the $30.4m increase in production related taxes to $33.0m (2010: $2.6m) following a new tax code becoming effective in Ukraine on 1 January 2011. This replaced most of the previous tax laws and removed uncertainty over the applicability of future rental fee payments by PPC, the Group's Ukrainian operating subsidiary. Accordingly PPC has been subject to, and paying, such fees. Production based taxes for PPC on a boe basis increased 25 fold to $19.74/boe (2010: $0.80/boe).

Operating costs fell 27% to $9.0m (2010: $12.3m). On a barrel of oil equivalent basis the fall in operating costs was 10%, to $5.23/boe (2010: $5.81). Depletion, Depreciation and Amortisation ("DD&A") fell 12% to $16.3m (2010: $18.5m), reflecting the 19% fall in production in the period partially offset by an increase in the forecast total capital pool. On a boe basis this increased capital pool results in a 9% increase in the Group's combined DD&A unit rate to $9.51/boe (2010: $8.74/boe).

Administrative expenses excluding movements in foreign exchange were maintained at $11.5m (2010: $11.5m). The Group benefited from a $1.2m foreign exchange gain in the period (2010: a loss of $3.1m).

Exploration costs expensed were down 21% at $6.3m (2010: $7.9m). The write-off of exploration costs in the period relate entirely to exploration wells in the Turkeve and Hernad licences in Hungary.

Taxation

The total tax charge for the period was $8.6m (2010: $14.0m). The 38% fall reflects a combination of the lower profitability, in itself being driven down by the production based taxes noted above, in addition to a reduced rate of corporation tax applicable in Ukraine. However, and as expected, the effective all-in total tax rate (i.e. combining production and corporation taxes) has gone up despite the fall in the corporation tax charge itself.

As previously announced, in December 2010 a new Ukrainian income tax rate was introduced starting at 25% to March 2011 and progressively reducing to 16% by 1 January 2014.

In addition a new tax code became effective in Ukraine on 1 January 2011 in the area of production related tax. The new tax code has removed previous uncertainty over the applicability of rental fee payments by PPC in respect of its oil and gas assets and accordingly PPC has been liable to and is paying such fees. The fees are levied on production volumes in accordance with a rates schedule which may change from time to time. The expense for the period under review is $33.0m compared with $2.6m in the same period during 2010. The expense has been recognised in cost of sales.

Effective tax rate

The table below shows the Group's effective tax rate as well as the all-in effective tax rate which takes into account the impact of production based taxes and removes the effect of special items and non-recurring items on the Group's tax charge.

1 The all-in effective tax rate is calculated as the income tax expense plus production related taxes and removing the tax effect of non-recurring items, divided by profit before tax which is adjusted for production based taxes, special items and other non-recurring items.

The effective rate of tax for the six months to 30 June 2011 2011 was 26.3% compared to a rate of 28.5% in the same period in the prior year principally as a result of the reduced rate of corporation tax applicable in Ukraine from 1 April 2011 of 23% (2010: 25%).

The all-in effective tax rate, which is a more representative tax rate on the recurring profits of the Group's subsidiary businesses, was 58.2% for the six months to 30 June 2011 compared to 31.4% for same period in 2010. The Group's all-in effective tax rate is higher when compared to the prior year mainly due to the proportionately higher production based taxes charged as compared to the increased underlying profitability of the Group.

Rental fee payments on oil and gas assets are determined independently of the profitability of operations. Consequently, in periods when the gas price is at elevated levels, the profitability of the operations increases and, assuming all other variables remain constant, the all-in effective tax rate decreases as the impact of rental fees lessens due to its volume-based nature. Whilst higher gas prices result in a higher absolute amount of taxes being levied, the all-in effective tax rate decreases. Conversely, during periods of low gas prices, the all-in effective tax rate increases.

Profit for the Period

The profit for the period of $24.1m is 31% down on the comparative period (2010: $35.1m). As noted above, while there are a number of contributing factors to this reduction, the most significant factor is the impact of the new tax code in Ukraine effective from 1 January 2011. The Group has partially mitigated the impact of the tax change through reduced operating costs and has benefited from higher commodity prices. Basic earnings per share fell 32% to 14.00 cents (2010: 20.72 cents) in line with the reduced profit, given the de-minimis increase of shares in issue.

Cash Flows and Net Cash

Net cash from operating activities was down 5% at $49.8m (2010: $52.4m). Underlying this reduction is the 25% reduction in cash generated from operations before changes in working capital. In line with all metrics post revenue, this mainly reflects the increased production taxes paid by the group in Ukraine as further described above. Despite this the cash generated from operations before changes in working capital represents 53% of gross revenue (2010: 73%). Changes in working capital in the period had a $1.7m positive effect on net cash flow compared with a $9.1m negative effect for the equivalent period in 2010.

Total cash outflow on investing activities was $100.1m (2010: $70.8m). Of this, $97.9m related to capital investment (2010: 68.3m) and $2.2m to the final contingent consideration in relation to the 2007 acquisition of YGE (2010: $3m). The $97.9m of capital investment is materially consistent with the amount invested in H2 2010 ($104.5m), reflecting relatively constant level of re-development activity on YGE's Koshekhablskoye field, which accounted for 62% of the total for the period. At the end of the period the carrying value of the Group's oil and gas assets in Russia ($239.1m which includes the $50m acquisition cost) exceeded the value of the Group's Ukrainian oil and gas assets ($226.7m) for the first time and is indicative of the scale of the Russian project, it's importance to the Group and the opportunity it represents.

Interest received in the period was $0.1m (2010: $0.6m) reflecting both the low interest rate environment and the reduced cash deposits held by the Group.

Net Cash inflow from financing activities in the period was $41.1m (2010: $51.6m). Proceeds from the placing of shares were $0.1m (from the exercise of employee share options) compared to the $58.4m in 2010 from the January 2010 placing of 14.3m shares.

Funds received from borrowings in the period net of cost total $58.4m (2010: Nil). Of this total $8.9m relates to funds drawn out at period end in relation to a $15m draw-down facility with Crédit Agricole in Ukraine, and $49.5m (net of costs) relates to funds received in respect of the prepaid swap transaction completed with Credit Suisse in June. In June 2011, Credit Suisse advanced $50m to the Group for working capital and other unrestricted purposes. The loan repayment is over 18 months, with an initial three month repayment holiday to September 2011 concluding with a final payment in November 2012. Of the funds received from Credit Suisse, $9.5m is presented as restricted cash in accordance with the terms of the prepaid element of the transaction.

The key terms of the swap element of the transaction are that the Group has sold forward 36,000 bbl/month of crude at $94/bbl Urals Med over the term of the loan, with a cap at $130/bbl Urals Med where additional value over this amount is retained by the Group.

Total dividends paid to shareholders in the period amounted to $7.2m (2010: $6.7m).

The resultant decrease in cash and cash equivalents in the period before adjusting for foreign exchange effects was $9.1m (2010: an increase of $33.3m). As in 2010 the Group's cash flow continues to reflect the significant redevelopment project in Russia, where, in addition to the acquisition cost, a cumulative total of $263m has been invested at the end of the period. The YGE redevelopment project is scheduled for commencement of commercial gas sales by the end of the year and during 2012 the cash flow profile in relation to the project will change accordingly, i.e. from a net recipient of Group cash to a net contributor.

Total cash and cash equivalents at the end of the period excluding restricted cash balances was $53.5m or $63.6m including restricted cash, compared to the June 30 2010 total of $107.2m and 31 December 2010 total of $62.0m.

Financial instruments

We employ a number of financial instruments to finance the Group's operations. These include cash and liquid resources, together with items such as receivables and payables that arise directly from our operations.

In June 2011 the Group entered into a prepaid swap transaction with Credit Suisse 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. Under the swap JKX has sold forward 36,000 bbl/month of crude at $94 Urals Med, with a cap at $130 Urals Med.

Financial review

1 Total cash is Cash and cash equivalents plus Restricted Cash.

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

3 Net cash is Total cash less Gross Borrowings.

4 Return on average capital employed is the annualised Profit for the period divided by average capital employed.

Statement of directors' responsibilities

The directors confirm that this condensed consolidated interim financial information has been prepared in accordance with IAS 34 as adopted by the European Union, and that the interim management report includes a fair review of the information required by the Disclosure and Transparency Rules 4.2.7 and 4.2.8, namely:

·; an indication of important events that have occurred in the first six months and their impact on the condensed set of financial information, and a description of the principal risks and uncertainties for the remaining six months of the financial year; and

·; material related party transactions in the first six months and any material changes in related party transactions described in the last annual report.

The directors of JKX Oil & Gas plc are listed in the JKX Oil & Gas plc Annual Report for 31 December 2010 and a list of current directors is maintained on the JKX Oil & Gas plc website www.jkx.co.uk.

By order of the Board

Dr Paul Davies

Chief Executive Officer

31 August 2011

B J Burrows

Finance Director

31 August 2011

Independent review report to JKX Oil & Gas plc

Introduction

We have been engaged by the company to review the condensed consolidated interim financial information in the half-yearly financial report for the six months ended 30 June 2011, which comprises the Condensed Consolidated Income Statement, Condensed Consolidated Statement of Comprehensive Income, Condensed Consolidated Statement of Financial Position, Condensed Consolidated Statement of Changes in Equity, Condensed Consolidated Statement of Cash Flows and related notes. We have read the other information contained in the half-yearly financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed consolidated interim financial information.

Directors' responsibilities

The half-yearly financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half-yearly financial report in accordance with the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.

As disclosed in note 2, the annual financial statements of the group are prepared in accordance with IFRSs as adopted by the European Union. The condensed consolidated interim financial information included in this half-yearly financial report has been prepared in accordance with International Accounting Standard 34, "Interim Financial Reporting", as adopted by the European Union.

Our responsibility

Our responsibility is to express to the company a conclusion on the condensed consolidated interim financial information in the half-yearly financial report based on our review. This report, including the conclusion, has been prepared for and only for the company for the purpose of the Disclosure and Transparency Rules of the Financial Services Authority and for no other purpose. We do not, in producing this report, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

Scope of review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, 'Review of Interim Financial Information Performed by the Independent Auditor of the Entity' issued by the Auditing Practices Board for use in the United Kingdom. A review of interim financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed consolidated interim financial information in the half-yearly financial report for the six months ended 30 June 2011 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.

PricewaterhouseCoopers LLP

Chartered Accountants

London

31 August 2011

Notes:

(a) The maintenance and integrity of the JKX Oil & Gas plc web site is the responsibility of the directors; the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the interim report since it was initially presented on the web site.

(b) Legislation in the United Kingdom governing the preparation and dissemination of financial information may differ from legislation in other jurisdictions.

Condensed Consolidated Income Statement

Condensed Consolidated Statement of Comprehensive Income

Condensed Consolidated Statement of Financial Position

Condensed Consolidated Statement of Changes in Equity (unaudited)

Condensed Consolidated Statement of Cash Flows

Notes to the interim financial information

1. General information and accounting policies

JKX Oil & Gas plc (the ultimate parent of the Group) is a public limited company listed on the London Stock Exchange and incorporated in England. The registered office is 6 Cavendish Square, London, W1G 0PD and the principal activities of the Group are exploration, appraisal, development and production of oil and gas reserves. The registered number of the Company is 03050645.

The condensed consolidated interim financial information incorporate the results of JKX Oil & Gas plc and its subsidiary undertakings as at 30 June 2011 and was approved by the directors for issue on 31 August 2011.

This condensed consolidated interim financial information does not constitute accounts within the meaning of section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 December 2010 were approved by the Board of directors on 19 April 2011 and delivered to the Registrar of Companies. The report of the auditors on those accounts was unqualified, did not contain an emphasis of matter paragraph and did not contain any statement under section 498(2)-(3) of the Companies Act 2006.

This condensed consolidated interim financial information has not been audited, but was the subject of an independent review carried out by the Company's auditors, PricewaterhouseCoopers LLP.

2. Basis of preparation

This condensed consolidated interim financial information for the six months ended 30 June 2011 has been prepared in accordance with the Disclosure and Transparency Rules of the Financial Services Authority and with IAS 34, 'Interim financial reporting' as adopted by the European Union. The condensed consolidated interim financial information should be read in conjunction with the annual financial statements for the year ended 31 December 2010 which were prepared in accordance with International Financial Reporting Standards as adopted by the European Union. A copy of the annual financial statements is available on the company's corporate website (www.jkx.co.uk) or from the company's registered office.

The directors are satisfied that the Group has sufficient resources to continue in operation for the foreseeable future, a period of not less than 12 months from the date of this report. Accordingly, they continue to adopt the going concern basis in preparing the financial statements.

3. Accounting policies

Except as described below, the accounting policies adopted are consistent with those used in the annual financial statements for the year ended 31 December 2010 and those expected to be applied in the 31 December 2011 annual financial statements.

Taxes on income in the interim period are accrued using the tax rate that would be applicable on expected total annual earnings.

Borrowings

Borrowings are initially measured at fair value, net of transaction costs and are subsequently measured at amortised cost using the effective interest method, with interest expense recognised on an effective yield basis. The effective interest method is a method of calculating the amortised cost of a financial liability and of allocating interest expense over the relevant period. The effective interest rate is the rate that exactly discounts estimated future cash payments through the expected life of the financial liability, or, where appropriate, a shorter period.

Derivative financial instruments

During the period the Group has used a derivative financial instrument to manage its exposure to fluctuations in oil prices.

Derivative financial instruments are stated at fair value.

The purpose for which a derivative is used is established at inception. To qualify for hedge accounting, the derivative must be 'highly effective' in achieving its objective and this effectiveness must be documented at inception and throughout the period of the hedge relationship. The hedge must be assessed on an ongoing basis and determined to have been 'highly effective' throughout the financial reporting periods for which the hedge was designated.

For the purpose of hedge accounting the hedge entered into during the period has been classified as cash flow hedge where they hedge exposure to variability in cash flows that are either attributable to a particular risk associated with a recognised asset or liability or forecasted transaction.

For the cash flow hedge, the portion of the gains and losses on the hedging instrument that is determined to be an effective hedge is taken to equity and the ineffective portion, as well as any change in time value, is recognised in the condensed consolidated income statement. The gains and losses taken to equity are subsequently transferred to the condensed consolidated income statement during the period in which the hedged transaction affects the condensed consolidated income statement or if the hedge is subsequently deemed to be ineffective. A similar treatment applies to foreign currency loans which are hedges of the Group's net investment in the net assets of a foreign operation.

Gains or losses on derivatives that do not qualify for hedge accounting treatment (either from inception or during the life of the instrument) are taken directly to the condensed consolidated income statement in the period.

Restricted cash

Restricted cash is disclosed separately on the face of the statement of financial position and denoted as restricted when it is not under the exclusive control of the Group.

New and amended International Financial Reporting Standards adopted by the Group

There were no new standards, interpretations or amendments to standards issued and effective for the period which materially impacted the Group.

4. Segmental analysis

Reportable operating segments are based on the internal reports provided to the Chief Operating Decision Maker ("CODM") to evaluate segment performance, decide how to allocate resources and make other operating decisions. The primary segmental reporting format is determined to be the geographical segment according to the location of the asset. The Group has one single class of business, being the exploration for, development and production of oil and gas reserves.

Transfer prices between geographical segments are on an arm's length basis in a manner similar to transactions with third parties.

Inter-segment revenues are eliminated on consolidation. 

4. Segmental analysis (continued)

5. Property, plant and equipment and intangible assets

During the period the group acquired $101.0m additional assets (2010: $68.3m), with 99% (2010: 96%) being in Ukraine, Russia and Hungary on the Group's oil and gas producing and development assets and 10% (2010: 4%) being spent on intangible assets.

6. Other receivables

Long term receivables consist of VAT recoverable as a result of expenditures incurred in Russia. The receivables will be recovered following first production of gas.

7. Cash

Restricted cash

Pursuant to the pre-paid swap transaction noted below, the Group holds $9.5m (2010: $nil) in an account at Barclays Bank Plc, which is treated as restricted cash as this account is not under the exclusive control of the Group and the Group does not have immediate direct access to the funds.

At 30 June 2011 $0.6m (31 December 2010: $0.5m) of the cash held in Hungary at K & H Bank Zrt was restricted as under the Hungarian Mining Act the Group is required to deposit cash to cover compensation for any mine damage and the costs of recultivation, including environmental damage of the waste management facilities.

8. Borrowings

Pre-paid Swap

On 14 June the Group entered into a pre-paid swap transaction 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 is a zero coupon rate on the outstanding balance however under the transaction JKX has hedged forward sales of oil (see note 9).

Short-term borrowings, term loans and guarantees are secured by fixed and floating charges over the oil and gas assets of the Group.

Credit Facility

On 31 March 2011, 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 USD15.0m and will be available until 31 December 2011. 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.

9. Derivative liability

Pre-paid Swap

The pre-paid swap transaction with Credit Suisse International has been structured to enable repayment by JKX from future sales of oil. Under this structure, JKX has sold forward 36,000 bbl/month of crude at $94.00 Urals Med per barrel while retaining value if prices rise above $130 per bbl.

The Urals Med index is the closest international benchmark for the range of oil and gas produced by JKX and delivered in local markets. The volume allocated represents approximately 10% of the Group's current daily production on a barrel of oil equivalent basis.

As the amount of consideration payable to Credit Suisse International will change in response to the change in the Urals Med index and will be settled in the future, the payable is treated as a derivative liability.

10. Share capital

Equity share capital, denominated in Sterling, was as follows:

The Company did not purchase any treasury shares during 2011 (2010: nil). There were no treasury shares used in 2011 (2010: nil) to settle share options. There are no shares reserved for issue under options or contracts.

The Group issued 14,257,270 ordinary shares on 26 January 2010 (9.1% of the existing ordinary share capital issued). The ordinary shares issued have the same rights as the other shares in issue. The related transaction costs amounting to $2.2m have been netted off against the proceeds. The Group placed no new shares in 2011.

11. Provisions

12. Other cost of sales

Production based taxes have increased following a new tax code becoming effective in Ukraine on 1 January 2011 (see note 13).

13. Taxation

No liability to UK taxation has arisen during the six months ended 30 June 2011 (2010: $nil) due to the availability of tax losses and relief for overseas taxes paid on dividends received. The current tax charged in the period 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.

Factors that may affect future tax charges

A significant proportion of the Group's income continues to 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.

In March 2011, a reduction in the rate of UK corporation tax was announced in the UK Budget. The main rate of corporation tax effective from 1 April 2011 will be reduced from 27% to 26%. 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. New tax rates in the Ukraine will be as follows: from 1 January 2011 to 31 March 2011 - 25%; from 1 April 2011 to 31 December 2011- 23%; in 2012 - 21%; in 2013 - 19%; after 31 December 2013 - 16%. The deferred tax asset has therefore been recognised with due consideration of the tax rate effective on the expected unwinding of those temporary differences.

Taxation in Ukraine

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.

PPC has at times since its inception in 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. Specifically, application of production related tax pre 2009 has attracted scrutiny. 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 introduced (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.

The historic tax position in respect of Ukraine as it applies to the Group is explained more fully on page 101 of the Company's 2010 Annual Report & Accounts. The Group's position remains substantially unchanged to that described in the 2010 Annual Report and Accounts, with the Group believing no form of material additional production related taxes is currently applicable to PPC.

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 is paying such fees. 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.

14. Earnings per share

The calculation of earnings per ordinary share for the six months ended 30 June 2011 is based on the weighted average number of shares in issue during the period of 172,064,952 (30 June 2010: 169,617,269; 31 December 2010: 170,865,583) and the profit for the relevant period.

The diluted earnings per share for the six months ended 30 June 2011 is based on 173,300,486 (30 June 2010: 170,482,527; 31 December 2010: 171,680,730) ordinary shares calculated as follows:

15. Dividends

In respect of the full year 2010 a final dividend of 2.6 pence per share (in respect of the full year 2009: 2.7 pence per share) was paid on 24 June 2011. No interim dividend for 2011 is being paid or proposed.

Total dividends paid during the six months period to 30 June 2011 amounted to $7.2m (2010: $6.7m) and for the full year ended 31 December 2010 $13.2m (2009: $12.3m).

16. Reconciliation of profit from operations to net cash generated from operations

17. Capital commitments

Under the programmes for exploration, development and production of oil and gas assets in Hungary, Slovakia, Bulgaria, Ukraine and Russia, the Group had committed $6.4m to future capital expenditure on drilling rigs and facilities as at 30 June 2011 (30 June 2010: $9.6m; 31 December 2010: $3.8m).

18. Related-party transactions

Key management compensation amounted to $2.5m for the six months ended 30 June 2011 (30 June 2010: $1.9m).

19. Events after the reporting date

Liquefied Petroleum Gas (LPG) production commenced at our central production facility in Poltava, Ukraine on 4 July and commercial shipments are being dispatched daily by road tanker.

Glossary

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