MXP.L Regulatory News (MXP)

MAX PETROLEUM PLC

("MAX PETROLEUM" OR THE "COMPANY" AND TOGETHER

WITH ITS SUBSIDIARIES, THE "GROUP")

[AIM: MXP]

2013 ANNUAL REPORT AND ACCOUNTS AND NOTICE OF AGM

22 August 2013

Max Petroleum, an oil and gas exploration and production company focused on Kazakhstan, today announces the publication of its annual report and accounts for the year ended 31 March 2013. The Company also announces that its Annual General Meeting will be held at 11:00 am on Wednesday 25 September 2013, at the Lansdowne Club, 9 Fitzmaurice Place, Mayfair, London W1J 5JD. A copy of the Company's annual report will be available on the Company's website at www.maxpetroleum.com and will be posted to shareholders with the notice convening the Annual General Meeting providing details of the venue, on or before 30 August 2013.

HIGHLIGHTS

1 Adjusted EBITDA is defined as operating profit/(loss) before depreciation, depletion and amortisation, share-based payment expense, exploration and appraisal costs, and impairment charges. Adjusted EBITDA is a non-IFRS performance measure with no standard meaning under IFRS, and is reconciled to the income statement in note 22 to the accompanying financial information.

2As estimated by the Ryder Scott Company, the Group's competent person.

Financial highlights:

· Revenue of US$93.3 million during the year ended 31 March 2013, up 86% compared to US$50.2 million during the year ended 31 March 2012.

· Average realised selling prices increased 51% as a result of increased exports relative to domestic sales since the Zhana Makat field entered full field development, providing the Group with the right to export up to 80% of the field's production.

· Entered into a US$90 million loan agreement with SB Sberbank JSC to refinance the Group's senior debt facility, redeem all of the Group's convertible bonds for a combination of cash and shares, and provide up to US$36.6 million for drilling future post-salt wells.

· Financed four of the post-salt exploration wells drilled during the year by executing a US$7 million equity for services agreement with Zhanros Drilling LLP.

Operational highlights:

· Received regulatory approval to extend the exploration period of the Blocks A&E Licence by two years until March 2015, allowing the Group to continue the exploration, appraisal and development of its post-salt assets, as well as additional time to complete drilling the pre-salt NUR-1 well.

· The Asanketken field was granted trial production status in May 2013 and the Borkyldakty field was granted full field development status in July 2013.

· During the year ended 31 March 2013, the Group drilled nine post-salt wells, including five exploration wells generating two commercial discoveries at Baichonas West and Eskene North, and four successful appraisal and development wells.

· In August 2013, the Group entered into a memorandum of understanding with Halliburton Kazakhstan LLP for the provision of integrated project management services for the drilling and completion of the NUR-1 pre-salt well.

· Since 31 March 2013, the Group drilled 12 post-salt wells, including nine successful appraisal and development wells, one non-productive appraisal well and two exploratory dry holes.

· Currently the Group is producing in excess of 4,500 bopd, including 2,900 bopd from fields in full field development. The Group expects average daily production for the year ended 31 March 2014 to be between 4,500 and 5,500 bopd.

KEY PERFORMANCE INDICATORS

The Group's key financial and performance indicators during the year were as follows:

1 Operating cost equals cost of sales less depreciation, depletion and amortisation (see note 5 to the accompanying financial information). The Group believes it is useful to its shareholders to present this information in a modified format.

2 Adjusted EBITDA is defined as operating profit/(loss) before depreciation, depletion and amortisation, share-based payment expense, exploration and appraisal costs, and impairment losses. Adjusted EBITDA is a non-IFRS performance measure with no standard meaning under IFRS, and is reconciled to the income statement in note 22 to the accompanying financial information.

3 Reserves estimated by the Ryder Scott Company, the Group's competent person.

4 Contingent resources in-place estimated by the Ryder Scott Company

JOINT CHAIRMEN'S STATEMENT

Robert B Holland and James A Jeffs, Executive Co-Chairmen, wrote in the Joint Chairmen's Statement in this year's 2013 Annual Report and Accounts:

"There is no denying that during fiscal year 2013 Max Petroleum experienced a major disappointment in failing to reach the target depth of our NUR-1 deep well. However, this was followed by a series of operational, regulatory and financing successes that has put us in a stronger position to develop our shallow asset base while we continue to pursue the exploration upside in our deep, pre-salt portfolio.

One of the most important developments is Max Petroleum's evolution from a pure exploration play to a viable production company with significant exploration potential. During the last fiscal year we generated US$93 million in revenue on record production of 1.2 million barrels resulting in over US$40 million of cash generated from operations. We are in a strong position to build on this platform over the next several years as we continue to evaluate our shallow discoveries and move them into continuous trial production and then on to full field development and export sales.

The Government of Kazakhstan has continued to encourage us as we successfully amended our Licence to extend our exploration period by two years. The Licence extension, along with a comprehensive financial restructuring, has allowed us to move into fiscal year 2014 with a stronger balance sheet essential to unlocking the value of our shallow portfolio, as well as providing additional time to finish testing NUR-1, which we continue to believe holds great potential value for our shareholders.

With the assistance of, and advice from, numerous industry and academic experts, including Halliburton, we have carefully reviewed and considered lessons learned and alternative ways forward for drilling NUR-1 to its target depth and believe we have arrived at a technical solution. Halliburton's involvement is important for the execution of the operation and to attract the financing necessary to complete the well, which continues to be a high priority.

Our languishing share price remains a source of frustration for us and our shareholders, but we believe in the underlying tangible value that is being generated by our shallow assets and our exploration upside. We will also remain diligent in pursuing transformative initiatives that have the potential to enhance shareholder value significantly.

We appreciate our shareholders' patience as we move forward on all these fronts."

ANALYST AND INVESTOR CONFERENCE CALL

There will be a conference call today to discuss this results announcement at 2pm British Summer Time. If you wish to participate in the call and have the opportunity to ask questions then please dial in early to register your details and to allow a prompt start to the call. Dial-in details are as follows:

UK dial-in +44 (0) 800 694 0257

US dial-in +1 866 966 9439

Conference ID 33069749

Enquiries:

Richard Hook, Chief Operating Officer of Max Petroleum, is the qualified person that has reviewed and approved the technical information contained in this announcement. Mr Hook is a member of the Houston Geological Society and holds both Masters and Bachelors of Science degrees in geology.

BUSINESS REVIEW

The fiscal year ended 31 March 2013 was a year of complex challenges for Max Petroleum as well as a period of significant operational progress as the Group set records for production, revenue and operating cash flow. Max Petroleum experienced a major setback with the suspension of its deep, pre-salt NUR-1 well in July 2012 due to technical problems, as the Group sought additional capital to refinance its senior debt facility and fund ongoing exploration and production activities while it faced the approaching end of the exploration period of its Blocks A&E Licence in Western Kazakhstan (the "Licence") in March 2013. The most serious of these regulatory and financial challenges were dealt with in the latter half of the fiscal year. The Group successfully refinanced its senior debt facility and restructured its balance sheet in December 2012 to allow for the future appraisal and development of its shallow portfolio. This restructuring was followed by the Group's successful extension of the exploration period of the Licence by two years until March 2015, allowing for the continued exploration, appraisal and development of its post-salt assets, as well as additional time to complete drilling the NUR-1 well.

The Group's comprehensive restructuring was made possible by the strong fundamentals of the Group's post-salt asset base. Max Petroleum increased annual revenue over the previous year by approximately 86% to US$93 million with record production of 3,346 bopd during the period, generating US$40 million in cash from operating activities. The revenue increase was positively impacted by the Group's first post-salt discovery, Zhana Makat, being placed on full field development ("FFD") in March 2012 allowing 80% of its production to be sold on the export market. These results reflect Max Petroleum's continuing maturation into a production and development company, as more of its shallow fields move from test into trial production ("TPP") and then onto FFD. The Group expects fiscal year March 2014 production to average between 4,500 and 5,500 bopd, with approximately 50% of the production being generated from fields on FFD. The Group also added two new discoveries out of five shallow exploration wells drilled during the period, bringing the total number of post-salt discoveries to eight with an exploration success rate of approximately 35%.

Although the nature of the Group's business has evolved as development drilling and production have increased, it still offers exploration upside as reflected by the pre-salt potential of its NUR-1 well in Block E. The Group has been able to refocus on its plans to complete NUR-1 now that the two-year extension of the Licence has provided the additional time to do so and that there is clear Government support for seeing the well completed. Internal and external post-appraisal analysis of the results of drilling NUR-1 have given the Group's management a high degree of confidence that the well can be re-entered successfully and drilled down to its target depth of 7,250 metres. This was recently corroborated by a geomechanical study of the well performed by Halliburton, one of the world's largest energy service companies with extensive experience drilling high pressure pre-salt wells across the globe. Halliburton has subsequently prepared an updated conceptual well design and programme for re-entering the well that the Group intends to use as the basis of its future re-entry operation for NUR-1. Max Petroleum has entered into a memorandum of understanding with Halliburton whereby Halliburton will provide integrated project management services for the re-entry and completion of NUR-1, including supervising the drilling and well site monitoring of the well. The Group estimates that the incremental costs of drilling NUR-1 will be approximately US$20 million and is actively seeking partners to farm in to its deep rights in the Licence to finance NUR-1 and proceed with the re-entry operations as soon as practicable. The NUR-1 well is designed to test the Emba B prospect with mean resource potential of 467 mmboe and a 29% geological chance of success.

In conjunction with dealing with the problems encountered drilling the NUR-1 well in July 2012, the Group was required to seek additional debt and equity financing in order to complete its post-salt exploration programme and underpin future appraisal and development drilling activities. It was also necessary to refinance its senior credit facility with Macquarie Bank Limited ("Macquarie" and the "Macquarie Facility") and its outstanding convertible bonds (the "Bonds"), which were due to maturein March and September 2013, respectively. In August 2012, the Group entered into a US$7 million equity for services agreement with its drilling contractor (the "Zhanros Agreement") to fund the drilling of four post-salt exploration wells that subsequently generated two shallow discoveries. The Zhanros Agreement allowed the Group to progress its exploration efforts at a critical juncture while it was working on restructuring its borrowings. In December 2012, the Group closed a new secured US$90 million credit facility with Sberbank (the "Sberbank Facility") as part of a comprehensive restructuring of its outstanding debt facilities, which included the refinancing of the Macquarie Facility, the restructuring of the Bonds, (together, the "Restructuring"), and providing an additional US$36 million in working capital to fund the Group's shallow drilling programme. The Restructuring reduced Max Petroleum's outstanding senior and convertible debt from approximately US$140 million to US$90 million and more closely aligned the maturity of the Group's new debt obligations with the appraisal and development timeline of the Group's shallow assets.

As a result of the Restructuring and the Licence extension, the Group has been able to progress the appraisal and development of its shallow asset base, with up to 35 post-salt wells planned for the fiscal year-ended 31 March 2014 of which 12 wells had been drilled as of 15 August 2013. The Group was also able to transfer the Asanketken field to TPP in May 2013 and the Borkyldakty field to FFD in July 2013.

OUR STRATEGY

Max Petroleum's strategy is to increase reserves, production and cash flow from its existing and future shallow, post-salt discoveries in its Blocks A&E Licence area, while continuing to pursue the higher impact exploration potential of its pre-salt portfolio. The Group's Licence is located in the Pre-Caspian Basin in Western Kazakhstan, offering a unique combination of high quality exploration opportunities with significant existing transportation and production infrastructure.

OPERATIONS REVIEW

As at 31 March 2013, the Group has made a total of eight post-salt discoveries, including the Zhana Makat, Borkyldakty, Uytas, Asanketken, East Kyzylzhar I, Sagiz West, Baichonas West and Eskene North fields. The Group drilled nine wells during the year, including five exploration wells generating two discoveries at Baichonas West and Eskene North, two appraisal wells at Asanketken and two development wells at Zhana Makat. 

For the year ended 31 March 2014, the Group expects to drill up to 35 wells consisting of two exploration wells and up to 33 appraisal and development wells, including:

· five development wells in Zhana Makat;

· ten appraisal and development wells in Sagiz West;

· 13 appraisal and development wells in Uytas;

· one development well in Borkyldakty; 

· two appraisal wells in Baichonas West; 

· one appraisal well in Eskene North; and

· one appraisal well in East Kyzylzhar I.

The Group is progressing through the current year's drilling programme with three rigs under contract. Since 31 March 2013, the Group has drillednine successful appraisal and development wells, one non-productive appraisal well, and two exploratory dry holes.

A principal focus of the remaining shallow drilling programme for the current year is to appraise both the Uytas and Sagiz West fields and gather the information necessary to formulate the field development plans required to apply for TPP. At Uytas a third shallow rig has recently been contracted to drill ten additional appraisal wells. The new rig is truck mounted for fast, inexpensive movement between wells, most of which target Cretaceous reservoirs at depths of less than 200 metres. Up to nine additional appraisal wells are planned for Sagiz West starting in August 2013, based on higher fold 3D seismic data and the results of the SAGW-4 well. Borkyldakty, Baichonas West and Eskene North will each have one additional well drilled this year, with further drilling being considered for East Kyzylzhar I, Asanketken and Zhana Makat depending on the results of new seismic data and well performance.

Facilities upgrades have been made at Zhana Makat where a new gathering system has allowed the further development of the southern portion of the field, and an oil export pipeline, due to be commissioned in the fourth quarter of 2013, is expected to reduce transportation costs for all of the production running through the Zhana Makat facility by approximately US$4 per bbl. The Group has also invested in new 3D seismic surveys across the Sagiz West and Asanketken fields, where the new data is critical for reserves evaluation and the planning of future field development. A new 3D seismic survey across East Kyzylzhar I will also be acquired later this summer, which will allow the Group to evaluate better the prospectivity of Jurassic and Cretaceous reservoirs in this area.

The Group estimates that total capital costs for the fiscal year ended 31 March 2014 relating to its post-salt programme will be up to US$60 million, including up to US$40 million in drilling related costs covering the 35 shallow wells planned for the period. The Group has incurred approximately US$15 million in capital expenditures through the four months ended 31 July 2013.

Production

During the fiscal year ended 31 March 2013, the Group produced 1,221,000 bbls, or 3,346 bopd, an increase of 19% from total production of 1,027,000 bbls, or 2,807 bopd, in the prior year. The Group is currently producing in excess of 4,500 bopd, including approximately 2,900 bopd from fields on FFD, resulting in approximately 2,300 bopd available for export.

Kazakhstan regulations require each field to progress through incremental regulatory stages of appraisal and development, including the testing and appraisal phase ("Test Production"), TPP, and then FFD. Test Production may last between one and three years depending upon the complexity of the field, during which time the Group may produce each zone in a well for up to 90 days in order to gather information necessary to move onto TPP. TPP typically lasts two to three years, during which time the field may be fully appraised and wells can be produced continuously. The Group only has rights to sell its production domestically during Test Production and TPP. Once the Group has enough information to prepare state reserves and a long-term full field development plan, it may obtain FFD status. FFD lasts for up to 25 years, during which time the Group may sell up to 80% of its production on the export market for prices that have historically averaged between US$10-20 per bbl higher than domestic prices on an after-tax basis.

The rate of production from fields on Test Production can be highly variable due to the uncertain production rates which are achievable from different productive zones in new exploration and appraisal wells, downtime incurred for pressure build-up tests, recompletions to move between zones and intentional variable production rates used during testing to gather data necessary to eventually apply for TPP status.

As at 31 March 2013, Zhana Makat was on FFD, Borkyldakty was on TPP, and the other six discoveries were in Test Production. The Group received regulatory approval to place Asanketken on TPP in May 2013 and the Borkyldakty field was approved for FFD in July 2013. All other fields are in various stages of appraisal in order to move to TPP and FFD in the future.

Reserves and Resources

As at 31 March 2013, the Group's competent person, Ryder Scott Company ("RSC"), estimated that the Group had 10.9 mmbo in proved and probable ("2P") reserves with an after-tax net present value discounted at 10% ("PV10") of US$184 million, an increase of 2% from 10.6 mmbo in 2P as at 31 March 2012 with a PV10 of US$215 million. RSC estimated that the Group's total proved, probable and possible ("3P") reserves decreased by 3% to 14.2 mmbo as at 31 March 2013, with a PV10 of US$236 million, from total 3P reserves in the prior year of 14.6 mmbo, with a PV10 of US$285 million.

The Group was able to increase reserves and contingent resources slightly from the prior period due to two new discoveries during the year and further 3D seismic and appraisal activities in the Asanketken field, offsetting production during the period of approximately 1.2 mmbo. This was as expected, given the limited drilling during the year and the early stage of the most recent Baichonas West and Eskene North discoveries. Changes in the PV10 valuations between periods is principally based on changes in oil prices and higher export customs duties imposed during the period by the Government of Kazakhstan. The fiscal 2014 drilling programme is expected to have a material positive impact on the Group's proved, probable and possible reserve base and the Group intends to prepare a competent person's report ("CPR") as at 30 September 2013, as well as its annual CPR for the year ended 31 March 2014.

As at 31 March 2013, RSC estimated the Group's in-place contingent resources to be approximately 110 mmbo, compared to in-place contingent resources of 107 mmbo for the prior year. RSC's estimates of in-place contingent resources do not take into account the Group's drilling activities after 31 March 2013, including the results of the SAGW-4 well drilled in June 2013 and newly acquired high-fold 3D seismic over the Sagiz West field.

Based on the combined results of the SAGW-4 well and the latest 3D seismic survey, the Group now estimates that a central productive fault block in the Sagiz West field has original oil in place ("OOIP") in a range between 35 and 48 mmbo. The outer flanks of the Sagiz West structure beyond this central fault block are still considered prospective, but are not included in this revised OOIP figure and will need to be tested by future drilling. Recoveries from the central fault block area are expected to be in the range of 20 to 30% with an expected recovery from this part of the Sagiz West field of approximately seven to 14 mmbo. Final results of the 3D processing and evaluation and further drilling may change this estimate in the future, and the Group plans to have RSC update the Group's resources estimates along with its reserves as of 30 September 2013. This updated CPR will reflect the important results from the ongoing appraisal programmes at Uytas and Baichonas West, as well.

The Group has also internally estimated an additional 126 mmbo of potential non-conventional in-placeresources at Uytas from the Cretaceous Albian reservoir which cannot be recovered using conventional primary production techniques. These resources were recognised by RSC in their report as being worthy of further evaluation but cannot be classified as contingent resources until they are demonstrated to be recoverable through a pilot production test.

A table showing the Group's reserves and resources as calculated by RSC for the years ended 31 March 2013 and 31 March 2012 is below.

FIELDS ON CONTINUOUS PRODUCTION

Zhana Makat

The Zhana Makat field was discovered in Block E in September 2006 and produces from Neocomian, Jurassic and Triassic reservoirs. Zhana Makat was placed on FFD in March 2012. Average production from the field for the year ended 31 March 2013 was approximately 2,100 bopd. Current production is in excess of 2,600 bopd. Since February 2013, the Group has drilled seven new development wells, which are designed to complete the development of the field. No further drilling is currently anticipated in Zhana Makat at this time. There are currently 26 producing wells in the field and one well is waiting to be completed. In addition, two Triassic wells are currently shut in due to high gas production rates, and will gradually be brought back on production later this year as gas production from other wells in the field declines. A gathering system in the southern portion of the field was completed in July 2013, and an oil pipeline is under construction with commissioning expected in the fourth quarter of 2013. The new oil pipeline will provide savings to the Group by lowering the cost to transport crude oil production to the regional export pipeline by approximately US$4 per bbl. Zhana Makat also acts as a regional hub, with the oil from the Borkyldakty field, as well as much of the test production from the Group's other fields being processed through the field's facilities.

Borkyldakty

The Borkyldakty field was discovered in Block E in February 2010 and produces from Triassic reservoirs. The field was placed on TPP in June 2011 and was shut-in during March 2013, while final approvals for FFD were under consideration by the Kazakhstan regulatory authorities. Production resumed when these approvals were received in July 2013. The field is currently producing approximately 250 bopd from two wells. The BOR-4 development well is currently being drilled and, depending on performance of the existing wells, a further well may be considered in 2014. With the addition of BOR-4, production from this field is expected to reach approximately 400 bopd. Crude oil from Borkyldakty is trucked 65 km to Zhana Makat where it is processed and put into the export pipeline. With FFD approval, 80% of the production from Borkyldakty is now available for sale on the export market, with the remainder being sold domestically. The Group plans to convert the non-producing BOR-2 well into a water injection well later in fiscal year 2014, which should reduce operating costs at the field.

Asanketken

The Asanketken field was discovered in Block E in March 2011 and produces from Jurassic reservoirs. In March 2013 the field was temporarily shut-in while waiting for final TPP approval by the Kazakhstan regulatory authorities, which was granted in May 2013. Since that time, average production from the four wells in the field has been approximately 1,500 bopd. Production from Asanketken is currently trucked approximately 210 km to the Zhamansor terminal, but plans are underway to use an existing terminal on an oil pipeline located approximately 40 km from the field. This change, combined with installing water disposal capability in the field, is expected to lower the field's production and transportation costs by approximately US$7 per bbl. A new high quality 3D seismic survey was acquired over the field in Spring 2013. The current interpretation indicates there is at least one more development well that will be drilled subsequent to the field being placed on FFD during 2014. The data is being further analysed to determine the possibility of new "outpost" locations that might also be considered for future drilling. Based on the latest 3D seismic and the four wells drilled at the field to date, at 31 March 2013 RSC estimates Asanketken's remaining 2P reserves at 2.0 mmbo.

FIELDS IN APPRAISAL

Uytas

The Uytas field was discovered in Block A in October 2010 and has productive Cretaceous and Jurassic reservoirs at shallow depths of between 100 and 400 metres. The Uytas field has been shut-in since the completion of test production from the initial four wells in July 2012. Drilling in the area resumed in May 2013 with two dry exploratory wells, including UTS-5 testing the Uytas North prospect and UTS-8 testing a potential extension of the Uytas field to the west. These wells were both in areas beyond the currently mapped extent of the Uytas field. As of 15 August 2013, three additional appraisal wells had been drilled in the Uytas field to depths of approximately 450 metres to confirm the extent of the Cretaceous and Jurassic accumulations. Two of these wells have found pay in both the Aptian (Cretaceous) and Jurassic reservoirs which are capable of conventional oil production and a third down-dip well on the Eastern flank of the field targeting Jurassic reservoirs was found to be wet and was abandoned. The appraisal drilling programme will continue this year, with three more 500 metre wells testing both Aptian and Jurassic formations, and a further seven 200 metre wells testing the Aptian only. These wells will be produced on test production for up to 90 days per reservoir and the results of this programme will provide the technical basis for moving the field to TPP status, which is expected in 2014. Uytas is expected to produce on TPP for two years and move to FFD in 2016.

During Test Production and TPP, oil will be trucked approximately 100 km to a terminal at Zhamansor, but a 40 km pipeline to a terminal near Sagiz is being planned during FFD, when more than 100 additional shallow wells are currently envisioned. The shallow Albian reservoirs, which appear to have oil saturation but will not produce naturally, will also be penetrated and carefully studied in the current appraisal programme and a pilot enhanced oil recovery project will be designed as appropriate to be completed during TPP. The 2P reserves reflected in the current RSC reportof 0.9 mmboare largely unchanged from the prior year and do not reflect any of the results of the current drilling campaign, as the Group did not begin that activity until after 31 March 2013.

Sagiz West

The Sagiz West field is a Triassic discovery made in Block E in September 2011. The Group has drilled four wells in the field to date and is planning another ten appraisal wells over the next year, commencing in August 2013.A new high quality 3D seismic survey has been recorded across Sagiz West field, and an initial interpretation has been completed. Final processing and the complete interpretation will be available in September 2013. Drilling also resumed earlier this year with the SAGW-4 well, which confirmed the extent of the field to the south of the initial discovery wells.

The SAGW-4 well in the Sagiz West field is currently testing a Triassic reservoir from depths ranging between 1,251 and 1,257 metres, producing at an initial rate of approximately 70 barrels of oil per day ("bopd") with a 16% water cut. Although porosities in this well are reasonably good, the permeability is not as high as seen in other reservoirs in the field making this zone a good candidate for hydraulic fracturing, a stimulation technique that is used routinely in these types of reservoirs around the world. The other more permeable reservoirs found in the field to date will not require stimulation. The Group anticipates that use of hydraulic fracturing may generate up to a five fold increase in production at a cost of approximately US$300,000 per well. The production data from this well will be used to help evaluate and design a stimulation programme for this reservoir across the field. Additionally, gas caps have been found in the SAGW-4 and SAGW-1 wells drilled on the crest of the structure.

The combined results of the SAGW-4 well and the current interpretation of the new 3D seismic survey confirm productive reservoirs in a central fault block which isestimated to have OOIP in a range between 35 and 48 mmbo. The outer flanks of the Sagiz West structure beyond this central fault block are still considered prospective, but are not included in this revised OOIP figure and will need to be tested by future drilling. Recoveries from the central fault block area are expected to be in the range of 20-30% with an expected recovery from this part of the Sagiz West field of approximately seven to 14 mmbo. Final results of the 3D evaluation and further drilling may increase this estimate in the future. RSC estimate Sagiz West has 2P reserves of 2.5 mmbo at 31 March 2013. However this does not take into consideration the latest 3D seismic survey or the drilling of the SAGW-4 well as both occurred subsequent to the year-end.

The Group expects to move Sagiz West into TPP in 2014 and FFD in 2016. Long-term plans are for up to 25 wells to be drilled in the field, including 20 producing wells and five injection wells. Development of the field will include both water injection for pressure maintenance in the reservoirs, as well as gas production and export. Initial production will be trucked to Zhana Makat, but development plans include an oil pipeline to be built to the Makat terminal and a gas pipeline to Zhana Makat. Construction of the pipelines and production facilities will take place in 2014 and 2015, with Sagiz West ultimately serving as a hub for production from other fields, including construction of a gathering system to move the future production from Baichonas West and Eskene North fields through Sagiz West onto market via our facilities at Zhana Makat.

Baichonas West

The Baichonas West field was discovered in Block E in September 2012, with the BCHW-1 well testing oil at an initial rate of 450 bopd from the Lower Jurassic formation. A second well drilled in the field, BCHW-2, has encountered gas in the Middle Jurassic reservoir and extensive shows in the Triassic, neither of which were seen in the BCHW-1 discovery well. The Triassic reservoirs are charged over a 170 metre interval but are of poor quality and did not produce at commercial rates during initial testing. Further drilling to the south will test possible improvement in the quality of Triassic reservoirs as well as delineate the extent of the productive Jurassic accumulation. A third well is planned in September 2013. The Triassic reservoirs may be a good candidate for hydraulic fracture stimulation. The current RSC 2P reserve estimate of 0.7 mmbo is based on the results of BCHW-1 only, and will be revised based on additional drilling results. Oil from Baichonas West is currently trucked to Zhana Makat for processing and sales, but ultimately will be sent by pipeline to Sagiz West and then on to market through our facility at Zhana Makat. Current plans are to progress the Baichonas West field to TPP in late 2014 and to FFD in 2016.

Eskene North

Eskene North is a Triassic aged field discovered in Block E in December 2012 by the ESKN-1 well. Testing began in May after obtaining all necessary regulatory approvals. To date the well has produced at indicative rates up to 25 bopd with no water. As expected, the reservoirs are of low permeability but fairly porous and oil filled, and as such are seen as a good candidate for hydraulic fracture stimulation which may increase productivity up to five fold. Current plans are to conduct the fracture stimulation in October 2013. The Group plans to drill theESKN-2 well later in 2013, with another appraisal well scheduled for 2014. Due to the large 90 metre oil column seen at ESKN-1 and the overall size of the structure, the Group estimates potential OOIP at 21 mmbo. The current RSC estimate of 2.6 mmbo of contingent resources in-place is much more conservative at this time, reflecting the need for further appraisal drilling across the large structure, as well as demonstration of the viability of hydraulic fracture stimulation before reserve estimates and economics can be properly determined. Oil from Eskene North is being trucked to Zhamansor, but in commercial development will be sent to Baichonas West, and then onto the Makat terminal via the Sagiz West pipeline. Eskene North is expected to progress to TTP in 2015 and to FFD in 2017.

East Kyzylzhar I

The East Kyzylzhar I field, a three-way faulted closure located in Block E, was discovered in August 2011 with the KZIE-1 well. The KZIE-2 appraisal well was drilled later that year and both wells were placed on test production. Permission to re-test the wells at East Kyzylzhar I was obtained and the two wells were placed on production in October 2012. KZIE-1 performed well, producing at an average rate of 230 bopd during the 90 day test. KZIE-2 continued to produce with very high water cut and is not considered to be commercial at this time. RSC estimate the field has 2P reserves of 0.1 mmbo at 31 March 2013. Development of the field has been hampered by the poor quality of the existing seismic data in the area. As a result of the encouraging production test at KZIE-1 and the Group's belief that there is additional prospectively for highly productive oil reservoirs in both Jurassic and Cretaceous formations in the area, a high quality 3D survey is planned for acquisition later this year. Drilling of two additional wells in the field in 2014 will be considered, contingent on the results of the new seismic. The Group plans to progress East Kyzylzhar I to TPP in 2014 and to FFD in 2016.

PROSPECTIVE RESOURCES

Post-salt potential

The two-year extension of the Licence is for further appraisal in the areas of the Group's recent discoveries. The Group will use this time, and the strength of its technical team who have been working in the areas of the discoveries for the past several years, to continue to look for further resource potential. This includes the drilling of possible extensions of producing fields such as Asanketken and East Kyzylzhar I on the basis of new 3D seismic. Further evaluation of the areas around Dossor Northwest and Tolegen West has also generated interest in some new areas that may be considered for drilling during the appraisal period. The Karasai South prospect was not drilled during the initial exploration period of the Licence and there are now no further plans to test it.

Pre-salt potential

While the failure to reach the geologic objectives at NUR-1 was a material setback for Max Petroleum, the testing of the pre-salt potential of the Licence remains one of the primary objectives of the Group. To that end, management has been working to both retain the opportunity to test the play during the current two-year extension, and to carefully analyse and post-appraise the initial attempt to drill NUR-1 so that any future efforts can benefit from what has been learned thus far. With the support of the Government of Kazakhstan, who recognise that testing this deep play is of strategic importance, the Group has made good progress on both fronts.

As a part of the work programme specified for the two-year appraisal extension, Max Petroleum has been granted permission to complete the drilling of NUR-1 on the Emba B prospect and, if it is successful, to drill the Kurzhem well on the Emba A prospect. The Emba A and B prospects have a combined unrisked mean resource potential of approximately 1.1 billion barrels of oil equivalent and are part of a much larger potential trend of similar prospects. As a part of the review of the results of NUR-1, the Ministry of Oil and Gas of the Republic of Kazakhstan recommended the Group organise a "Technical Roundtable" with experts in deep drilling including other operators in the area to evaluate the problems at NUR-1 and consider possible ways forward. A series of meetings were held with the experts and a protocol was issued, with the general conclusion that with certain modifications to the existing well design there is no technical reason the well cannot successfully be re-entered and drilled to the objective depth of 7,250 metres.

After the completion of the Technical Roundtable, the Group began to work with Halliburton, a company with experience in managing deep drilling worldwide, to further analyse the reasons NUR-1 failed and the feasibility of re-entry. The first step was to make a geomechanical study of the well to re-evaluate the design parameters for the well. This study was completed in June 2013 and a conceptual well design and revised drilling programme have been prepared. The existing well bore will be used to a depth of approximately 5,300 metres, where a window will be cut in the existing casing and a new well will be drilled from that point. The new programme differs from the original in that it will use slightly higher mud weights, and it incorporates the use of "expandable liners" to create the possibility of setting an additional protective string of casing should the well again encounter any drilling problems. Max Petroleum has signed a memorandum of understanding with Halliburton under which they will manage the re-entry of NUR-1 on behalf of the Group, thus bringing their technical expertise and experience to bear on this challenging and highly prospective project.

In order to complete drilling NUR-1 and evaluate its pre-salt potential, the Group requires additional financing. While this project is very important, the Group does not intend to risk its post-salt production assets to finance remaining drilling. For this reason, the Group is in discussions with various potential partners, both financial and industrial, to find a way forward to test the pre-salt potential of Block E without jeopardising the value of the post-salt portfolio.

Blocks A&E Licence extension

Max Petroleum has remained committed to the exploration, appraisal and development of the Blocks A&E Licence, both in the shallow, post-salt section where the Group has made eight discoveries and in the deep, pre-salt where the Group retains the goal of testing this high potential play at Emba B with the NUR-1 well. By granting a two-year extension across the entirety of the Licence, the Government of Kazakhstan continues to show its support for the Group and the progress that has been made in evaluating the Licence.

RESULTS OF OPERATIONS

The Group recognised a loss of US$10.1 million, or US$0.01 per ordinary share, for the year ended 31 March 2013, compared to a loss of US$8.2 million, or US$0.01 per ordinary share, during the prior year.

Oil sales volumes increased by 23% to 1,234,000 bbls compared to 1,004,000 bbls in the previous year, including 614,000 bbls sold into the domestic market generating US$29.2 million in revenue, or US$47.54 per bbl, and 620,000 bbls sold into the export market generating US$64.1 million in revenue, or US$103.51 per bbl. Comparatively, the Group's fiscal year 2012 sales volumes of 1,004,000 bbls included 954,000 bbls sold into the domestic market generating US$44.2 million in revenue, or US$46.36 per bbl, and 50,000 bbls sold into the export market generating US$6.0 million in revenue, or US$120.32 per bbl. Overall, sales revenue grew 86% to US$93.3 million (2012: US$50.2 million) as a result of significantly higher average price realisations since the Zhana Makat field entered FFD and the increase in sales volumes due to increased production at Asanketken and other fields on test production.

Costs of sales increased by 109% from US$33.5 million, or US$33.38 per bbl, in the year ended 31 March 2012 to US$70.1 million, or US$56.87 per bbl, in the year ended 31 March 2013, principally driven by higher taxes and transportation costs on export sales that are more than offset by the higher oil price received on the export market.

Costs of sales before depreciation, depletion and amortization ("DD&A") increased by 177% from US$17.5 million, or US$17.39 per bbl, to US$48.3 million, or US$39.17 per bbl, including field production costs, selling and transportation costs, and export and mineral extraction taxes ("production taxes"). The total costs of sales before DD&A for fiscal year 2013 of US$48.3 million includes US$11.6 million, or US$9.42 per bbl, in field production costs, US$14.3 million, or US$11.55 per bbl, in selling and transportation costs, and US$22.4 million, or US$18.19 per bbl, in production taxes. Comparatively, total costs of sales before DD&A for fiscal year 2012 of US$17.5 million includes US$8.2 million, or US$8.21 per bbl, in field production costs, US$6.4 million, or US$6.35 per bbl, in selling and transportation costs, and US$2.8 million, or US$2.82 per bbl, in production taxes.

Cash generated from operations increased by 43% from US$28.3 million for the year ended 31 March 2012 to US$40.4 million for the year ended 31 March 2013, consisting of net revenue from the production and sale of crude oil, offset by the Group's general and administrative expenses, plus prepayments from customers in Kazakhstan for crude oil sales. The increase is primarily due to higher sales volumes and higher netback revenues realised on export versus domestic sales during the most recent period.

The Group incurred US$7.0 million in exploration and appraisal costs written-off during the current year compared to US$4.4 million in 2012.

During the year ended 31 March 2013, the Group incurred total administrative expenses of US$17.3 million, compared to administrative expenses of US$17.8 million in 2012. Administrative expenses for the current and prior year principally reflect management and employee costs of the Group's operations in the United Kingdom, Kazakhstan and the United States. Administrative expenses also included non-cash share-based payment charges of US$3.6 million in the year ended 31 March 2013, compared to US$4.9 million in 2012, as well as US$1.7 million in costs relating to the Restructuring and the refinancing of the Macquarie Credit Facility.

Liquidity and capital resources

The Group finances its exploration and development activities using a combination of cash on hand, operating cash flow generated from the sale of crude oil production, borrowings under its credit facility with Sberbank and additional debt or equity financing as required.

The Group has eight post-salt discoveries with two fields producing under FFD, one field under TPP, and the remainder at varying stages of appraisal and development. As the Group continues to drill appraisal and development wells, it is increasing the overall productive capacity of its post-salt asset base. As the Group's discoveries progress from Test Production into TPP they are able to resume continuous production, and as they move from TPP to FFD, 80% of the production will be available to sell on export markets for a substantially higher price per bbl. The Group is currently producing in excess of 4,500 bopd generating over US$9 million per month in revenue and significant net cash flow from operations. For the current fiscal year ended 31 March 2014, it is expected that production will average between 4,500 and 5,500 bopd.

In December 2012, the Group closed the Restructuring whereby it reduced its debt obligations from approximately US$140 million to US$90 million, of which approximately US$53 million was utilised to repay Macquarie and certain tendering Bondholders. As of 15 August 2013, the Group had borrowed a total of US$78 million under the US$90 million Sberbank Facility, leaving US$12 million in available borrowing capacity to fund the ongoing post-salt drilling programme through 31 December 2013. The Sberbank Facility matures in November 2017 with quarterly amortisation payments beginning in March 2014.

As part of the Restructuring, approximately US$56.7 million in Bonds converted into the Company's ordinary shares in December 2012. The remaining US$26.7 million in outstanding Bonds (the "PIK notes") were modified such that they earn a coupon of 10% per annum, with interest payable in kind, and the maturity date was extended to 8 March 2018. It is expected that the PIK notes will mandatorily convert into the Company's ordinary shares at a conversion price of 5p per ordinary share during the remainder of 2013 on receipt of requisite Kazakh regulatory approvals.

In May 2013, the Group received regulatory approval of a two-year extension of the exploration period of the Group's Blocks A&E Licence by the Ministry of Oil & Gas of the Republic of Kazakhstan. This extension will allow the Group to finish drilling the pre-salt NUR-1 well on the Emba B prospect, with an option to drill the Kurzhem well on the Emba A prospect in the event the NUR-1 well is successful. The Group estimates it will cost approximately US$20 million in additional capital to finish drilling the NUR-1 well, which will not be funded out of the Sberbank Facility or the Group's existing capital resources. The Group is currently looking for financial or industry partners to farm in to the Group's deep rights on Blocks A&E to finance the drilling of NUR-1 and, if NUR-1 is successful, Kurzhem also.

The two-year licence extension also enables the Group to continue the appraisal and development programme for its post-salt assets. The Group estimates that it will incur up to US$60 million in post-salt capital expenditures during the fiscal year ended 31 March 2014, including up to US$40 million on drilling related costs, of which US$15 million has already been incurred as of 31 July 2013. The Group expects to fund the remaining post-salt capital expenditures using a combination of borrowings from the Sberbank Facility and cash flow from operations.

While the proceeds from the Sberbank Facility along with anticipated future cash flow from operations are expected to support the Group's ongoing post-salt exploration, appraisal and development activities, future capital requirements are difficult to predict accurately and can be materially impacted by the results of the Group's ongoing evaluation of its current post-salt discoveries. Based on the Group's cash flow forecasts, however, the directors believe that the combination of its current and expected future production and resulting net cash flows from operations, borrowings under the Sberbank Facility, and other potential sources of debt and equity capital provide a reasonable expectation that the Group will continue in operational existence for the foreseeable future.

MAX PETROLEUM PLC

CONSOLIDATED AND COMPANY INCOME STATEMENTS

For the year ended 31 March 2013

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED AND COMPANY STATEMENTS OF COMPREHENSIVE INCOME

For the year ended 31 March 2013

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED AND COMPANY BALANCE SHEETS

At 31 March 2013

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 March 2013

(in thousands of US$)

No interim or final dividend has been paid or proposed during the year.

MAX PETROLEUM PLC

COMPANY STATEMENT OF CHANGES IN EQUITY

For the year ended 31 March 2013

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED AND COMPANY CASH FLOW STATEMENTS

For the year ended 31 March 2013

(in thousands of US$)

MAX PETROLEUM PLC

NOTES TO THE FINANCIAL INFORMATION

For the year ended 31 March 2013

1. General information

Max Petroleum Plc ("Max Petroleum" or the "Company") and its subsidiaries (together the "Group") is in the business of exploration, development and production of oil and gas assets within the Republic of Kazakhstan. The Group owns the exploration and production rights to the Blocks A&E Licence (the "Licence"), which comprises two onshore blocks extending over 12,455 km2 in the Pre-Caspian Basin in Western Kazakhstan.

The Company is a public limited company incorporated and domiciled in the United Kingdom, quoted on AIM and listed on the Kazakhstan Stock Exchange ("KASE"). The address of its registered office is Second Floor, 81 Piccadilly, London, W1J 8HY, United Kingdom.

2. Basis of accounting and presentation of financial information

While the financial information included in this announcement has been prepared in accordance with the recognition and measurement criteria of International Financial Reporting Standards as adopted by the European Union (IFRSs as adopted by the EU), this announcement does not contain sufficient information to comply with IFRSs as adopted by the EU.

The financial information set out in this announcement does not constitute the Company's statutory accounts for the years ended 31 March 2013 or 2012, but it is derived from those accounts. Statutory accounts for 2012 have been delivered to the Registrar of Companies and those for 2013 will be delivered following the Company's Annual General Meeting. The auditors have reported on those accounts: their reports were unqualified and did not contain statements under s498(2) or (3) Companies Act 2006. The auditors' report on the 2012 accounts, whilst unqualified, contained an emphasis of matter which drew attention to the existence of a material uncertainty which may cast significant doubt about the Company's ability to continue as a going concern. The auditors' report on the 2013 accounts contained no emphasis of matter.

3. Going concern

The Group's business activities, together with the factors likely to affect its future development, performance and position are set out in the Business Review section of this announcement.

The Group finances its exploration and development activities using a combination of cash on hand, operating cash flow generated from the sale of crude oil production, borrowings under its credit facility with SB Sberbank JSC ("Sberbank" and the "Sberbank Facility") and additional debt or equity financing as required.

The Group has eight post-salt discoveries with two fields producing under FFD, one field under TPP, and the remainder at varying stages of appraisal and development. As the Group continues to drill appraisal and development wells, it is increasing the overall productive capacity of its post-salt asset base. As the Group's discoveries progress from Test Production into TPP they are able to resume continuous production and as they move from TPP to FFD, 80% of the production will be available to sell on export markets for a substantially higher price per bbl. The Group is currently producing in excess of 4,500 bopd generating over US$9 million per month in revenue and significant net cash flow from operations. For the current fiscal year ended 31 March 2014, it is expected that production will average between 4,500 and 5,500 bopd.

In December 2012, the Group closed a comprehensive restructuring whereby it reduced its debt obligations from approximately US$140 million to US$90 million, of which approximately US$53 million was utilised to repay Macquarie and certain tendering Bondholders. As of 15 August 2013, the Group had borrowed a total of US$78 million under the US$90 million Sberbank Facility, leaving US$12 million in available borrowing capacity to fund the ongoing post-salt drilling programme through 31 December 2013. The Sberbank Facility matures in November 2017 with quarterly amortisation payments beginning in March 2014.

As part of the Restructuring, approximately US$56.7 million in Bonds converted into the Company's ordinary shares in December 2012. The remaining US$26.7 million in outstanding convertible bonds were modified such that they earn a coupon of 10% per annum, with interest payable in kind, and the maturity date was extended to 8 March 2018. It is expected that the PIK notes will mandatorily convert into the Company's ordinary shares at a conversion price of 5p per ordinary share during the remainder of 2013 on receipt of requisite Kazakh regulatory approvals.

In May 2013, the Group received regulatory approval of a two-year extension of the exploration period of the Group's Blocks A&E Licence by the Ministry of Oil & Gas of the Republic of Kazakhstan. This extension will allow the Group to finish drilling the pre-salt NUR-1 well on the Emba B prospect, with an option to drill the Kurzhem well on the Emba A prospect in the event the NUR-1 well is successful. The Group estimates it will cost approximately US$20 million in additional capital to finish drilling the NUR-1 well, which will not be funded out of the Sberbank Facility or the Group's existing capital resources. The Group is currently looking for financial or industry partners to farm in to the Group's deep rights on Blocks A&E to finance the drilling of NUR-1 and, if NUR-1 is successful, Kurzhem also.

The two-year licence extension also enables the Group to continue the appraisal and development programme for its post-salt assets. The Group estimates that it will incur up to US$60 million in post-salt capital expenditures during the fiscal year ended 31 March 2014, including up to US$40 million on drilling related costs, of which US$15 million has already been incurred as of 31 July 2013. The Group expects to fund the remaining post-salt capital expenditures using a combination of borrowings from the Sberbank Facility and cash flow from operations.

While the proceeds from the Sberbank Facility along with anticipated future cash flow from operations are expected to support the Group's ongoing post-salt exploration, appraisal and development activities, future capital requirements are difficult to predict accurately and can be materially impacted by the results of the Group's ongoing evaluation of its current post-salt discoveries. Based on the Group's cash flow forecasts, however, the directors believe that the combination of its current and expected future production and resulting net cash flows from operations, borrowings under the Sberbank Facility, and other potential sources of debt and equity capital provide a reasonable expectation that the Group will continue in operational existence for the foreseeable future. For these reasons, they continue to adopt the going concern basis of accounting in preparing the annual financial statements.

4. Operating segments

Management has determined its operating segments based on the reports reviewed by the directorsfor the purposes of making decisions about allocating resources and assessing performance. In the opinion of the directors, the operations of the Group comprise one operating segment: oil and gas exploration and development and related activities. All of the Group's assets and liabilities, income and expense relate to this segment.

Geographical information

The Group conducts business within three geographical regions. The Group's operational activities are wholly focused in the Republic of Kazakhstan, supported by a technical team in Houston, USA. The Group's head office is in London, United Kingdom.

Revenue

All of the Group's revenue from external customers is derived from its operations in the Republic of Kazakhstan, as follows:

Included in revenues arising from sales from the Republic of Kazakhstan are revenues of US$53.4 million which arose from the Group's largest customer (2012: sales to Group's largest customer of US$30.5 million).

Non-current assets

The Group's non-current assets excluding financial assets by geographical location are as follows:

5. Cost of sales

The cost of crude oil inventories recognised as an expense and included in cost of sales amounted to US$30.3 million (2012: US$18.7 million).

6. Finance income

7. Finance costs

Other finance costs include US$1.4 million of fees relating to the refinancing of the Group's borrowings in December 2012.

Interest expense of US$7.1 million (2012: US$9.0 million) arising on the general borrowing pool during the year was capitalised in the cost of qualifying assets, calculated by applying a capitalisation rate of 10% (2012: 11%) to the average cumulative expenditure on such assets. The borrowing costs capitalised are included in 'additions' to intangible assets - exploration and appraisal expenditure.

8. Income tax expense

The Group's principal business activities are in the Republic of Kazakhstan, where corporate income tax ("CIT") applies at a rate of 20% of taxable income. Taxes on the production and sale of hydrocarbons are accounted for as cost of sales (see note 5).

The tax on the Group's loss before tax differs from the theoretical amount that would arise using the UK statutory rate of 24% (2012: 26%) applicable to the loss of the Group, as follows:

The tax on the Company's loss before tax differs from the theoretical amount that would arise using the UK statutory rate of 24% (2012: 26%) applicable to the loss of the Company, as follows:

9. Loss for the year

Loss for the year is stated after charging:

Exploration and appraisal costs for the year ended 31 March 2013 include a loss of US$1.1 million which arose on the disposal of inventories of drilling supplies (2012: $nil).

10. Intangible assets - exploration and appraisal expenditure

The US$182.0 million carrying value of the intangible exploration and appraisal asset at 31 March 2013 is substantially dependent on the outcome of the Group's pre-salt exploration programme.

During the year ended 31 March 2013, the Group encountered difficulties drilling the NUR-1 pre-salt well, and due to financial constraints, suspended the well. In May 2013, the Group received regulatory approval of a two-year extension of the exploration period of the Group's Blocks A&E Licence by the Ministry of Oil & Gas of the Republic of Kazakhstan. This extension will allow the Group to finish drilling the pre-salt NUR-1 well on the Emba B prospect, with an option to drill a well on the Emba A prospect in the event the NUR-1 well is successful. Any pre-salt drilling operations are subject to the Group obtaining additional third party financing. As the Group intends to recommence work on NUR-1 at a later date, the Group considers that it is appropriate for the related costs to remain capitalised. The net book value of exploration and appraisal expenditure at 31 March 2013 includes US$40.7 million directly relating to the NUR-1 pre-salt well (2012: US$27.0 million).

In assessing whether there were any indicators of impairment for intangible exploration and appraisal expenditure, management considered the carrying value of the assets compared to their expected recoverable amounts. The assessment for Blocks A&E was based on an estimate of the value of the estimated mean risked resources in the Licence area. While this estimate is very uncertain due to the risks inherent to oil and gas exploration, management of the Company is comfortable that the fair value of the Group's Blocks A&E exploration assets significantly exceeds its book value. If it were unsuccessful in drilling the NUR-1 well, the Group would have to reassess the carrying value of the whole of the intangible exploration and appraisal asset.

Included within exploration and appraisal expenditures at 31 March 2013 was a decommissioning asset of US$0.6 million (2012: US$0.4 million).

11. Oil and gas properties

Included within oil and gas properties at 31 March 2013 was a decommissioning asset of US$1.0 million (2012: US$1.1 million).

In assessing whether there were any indicators of impairment for oil and gas producing assets and associated property, plant and equipment at 31 March 2013, management considered the carrying value of the assets compared to their expected recoverable amounts. The expected recoverable amounts for the Group's producing fields were based on the competent person's report at 31 March 2013 and management estimates. The results of the comparison indicate that the expected recoverable amount of each field exceeds its net book value.

In estimating the expected recoverable amount of its producing fields, the future production from each field was based on the proved and probable reserves from the competent person's report and, where fields are at an early stage of appraisal, on management estimates. The revenue assumptions depend on the anticipated full field development date for each field. Prior to full field development, all production is sold domestically within Kazakhstan and once full field development has been achieved, 80% of production is allocated to international sales and 20% to domestic sales. The international sales price is based on a Brent crude futures strip covering the period to 2034, where prices per barrel range from US$85 to US$114. The domestic sales price estimates commence at US$45/bbl in 2013 and are escalated at 2% annually. The discount rate used was 10%.

12. Cash and cash equivalents

Group and Company

Under the terms of the Macquarie Facility (note 13), the Company was required to maintain a balance on a debt service reserve account representing the next three months' expected interest charge. The balance on this account at 31 March 2012 amounted to US$0.9 million, and is included in the total of cash at bank and on hand for the Group and Company, above. Following the repayment of the Macquarie Facility, there is no equivalent requirement at 31 March 2013.

Re-presentation of cash and cash equivalents

The Group has re-presented cash and cash equivalents to exclude balances required to be deposited in an environmental restoration and rehabilitation fund under the terms of the Group's Blocks A&E Licence. These balances are presented as restricted cash in the current year balance sheet and cash flow statement and the prior year equivalents have been re-presented on a comparable basis. The restricted cash at 31 March 2011 was US$1.6 million, and accordingly the cash and cash equivalents balance at that date has been re-presented from US$25.5 million to US$23.9 million. The restricted cash at 31 March 2012 was US$2.0 million, and accordingly the cash and cash equivalents balance at that date has been re-presented from US$3.6 million to US$1.6 million.

13. Borrowings

The fair value of the Group's bank borrowings at 31 March 2013 approximates to their gross carrying value of US$64.6 million (2012: US$50.2 million).

The fair value of the Bonds and PIK Notes at 31 March 2013 and 2012, determined by reference to the published closing price quotation from the Channel Islands Stock Exchange on that date, was as follows:

Debt restructuring

In December 2012, the Group closed a new secured US$90 million credit facility with Sberbank as part of a comprehensive restructuring of its outstanding debt facilities, comprising the refinancing of its credit facility with Macquarie Bank Limited ("Macquarie" and the "Macquarie Facility") and the restructuring of its convertible bonds (the "Bonds"), (together, the "Restructuring").

The Restructuring was conditional on Bondholder and shareholder approval, which was duly received at Bondholder and shareholder meetings on 20 December 2012.

The key terms of the Restructuring were as follows:

· The new Sberbank Facility would be used to repay the existing Macquarie Facility, to fund the cash portion of a tender offer made to Bondholders and to fund capital expenditures on the Group's shallow drilling programme.

· The Sberbank Facility bears interest at 11% and matures in November 2017, with quarterly amortisation beginning in March 2014.

· The Macquarie Facility was cancelled, with Macquarie receiving US$47 million plus all accrued but unpaid interest in December 2012 and a further US$3 million in March 2013, in full settlement of the US$52.2 million outstanding under the Macquarie Facility. The cancellation of the amounts outstanding under the Macquarie Facility resulted in a gain of US$2.2 million, recognised in the income statement as part of finance income.

· US$2.9 million of interest due on the Bonds on 8 September 2012, which had been deferred with the agreement of more than 75% of the Bondholders, was capitalised and added to the outstanding principal amount of the Bonds of US$85.6 million, with effect from 8 September 2012. A further US$1.7 million of interest, covering the period from 8 September 2012 to 19 December 2012, was capitalised and added to principal, resulting in a revised principal of US$90.2 million at the date of the Restructuring.

· Bondholders agreed to exchange the revised principal of the Bonds of US$90.2 million for a combination of cash and ordinary shares.

· Bondholders were invited to participate in a tender offer pursuant to which they could tender Bonds to the Company with an aggregate principal amount of up to US$17.1 million, whereby the Company would pay to tendering Bondholders a cash amount representing 50% of the principal amount tendered (up to a maximum of US$8.6 million). The Bonds accepted into the tender offer (the "Accepted Bonds") amounted to US$6.8 million and were cancelled and replaced by promissory notes of value US$3.4 million. The promissory notes accrued interest from 20 December 2012 until settlement at the rate of 6.75% per annum.

· In March 2013, the Company paid US$3.4 million to settle the promissory notes and accrued interest in full.

· In December 2012, US$56.7 million of the Bonds were converted into 709.0 million ordinary shares of the Company at a conversion price of 5p per ordinary share.

· The remaining outstanding Bonds (the "PIK notes"), which at the date of the Restructuring had a principal amount of US$26.7 million, will be mandatorily converted into ordinary shares following receipt of the requisite Kazakh regulatory approvals, expected during calendar year 2013.

Bank borrowings - Macquarie Facility

In June 2007, the Group entered into a US$100 million revolving mezzanine credit facility with Macquarie. The material provisions of the Macquarie Facility were as follows:

· Interest payable monthly at LIBOR plus 6.5%.

· Supplemental interest of 2% applied when there had been an event of default, payable monthly.

· Principal repayments due from 31 July 2012, comprising seven monthly payments of US$2.0 million until 31 January 2013, US$4.0 million on 28 February 2013 and the remaining balance on 31 March 2013.

· Secured by pledges in favour of Macquarie over substantially all of the Group's assets.

During the year, the Group was not in compliance with the terms of the Macquarie Facility, as the principal repayments of US$2.0 million per month commencing on 31 July 2012 were not paid. Additionally the Group was in breach of its banking covenants relating to certain financial ratios.

Pursuant to the Restructuring, Macquarie was repaid US$50 million in full and final settlement of the US$52.2 million outstanding under the Macquarie Facility. The cancellation of the amounts outstanding under the Macquarie Facility resulted in a gain of US$2.2 million, recognised in the income statement as part of finance income.

A reconciliation of the amounts outstanding on the Macquarie Facility is as follows: