2012 Annual Report & Accounts & Notice of AGM

MAX PETROLEUM PLC

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

WITH ITS SUBSIDIARIES, THE "GROUP")

[AIM: MXP]

2012 ANNUAL REPORT AND ACCOUNTS AND NOTICE OF AGM

24 August 2012

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 2012. The Company also announces that its Annual General Meeting will be held at 11:00 am on Monday 24 September 2012, 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 today and will be posted to shareholders with the notice convening the Annual General Meeting providing details of the venue, on or before 30 August 2012.

HIGHLIGHTS

A summary of the Group's financial and operational highlights are as follows:

·; 2P reserves2 of 10.6 mmbo, a 36% increase on 2011, but a decrease of 20% from 13.3 mmbo at the half year primarily due to the results of the SAGW-2 well and the greater complexity of the Sagiz West Field.

·; Contingent resources in-place2 of 107.0 mmbo, compared to none in 2011, and an increase of 74% from 61.3 mmbo at the half year.

·; Spudded NUR-1 in November 2011, drilling to approximately 5,700 metres where the drill pipe became stuck due to anomalously high pressures encountered in the Kungurian salt beyond the scope of the original well design.

·; Temporarily suspended drilling at NUR-1 and released the rig in July 2012, pending additional capital and regulatory approvals to complete the well.

·; Since 31 March 2011, drilled 19 post-salt wells, including five exploration wells generating two commercial discoveries at East Kyzylzhar I and Sagiz West, and 13 out of 14 successful appraisal and development wells across six fields.

·; As at August 2012, the remaining post-salt exploration portfolio consists of seven Triassic Rim prospects with unrisked mean resource potential of 67 mmbo.

·; Since year-end, entered into US$7 million equity for services agreement with Zhanros Drilling LLP to drill up to four post-salt exploration wells.

·; Received approval for Full Field Development at the Zhana Makat Field, which provided the Group with the right to export up to 80% of the field's production from April 2012.

·; Since year-end, daily production has averaged approximately 3,900 bopd generating around US$8.0 million in pre-tax revenue per month.

1 EBITDA is defined as operating profit/(loss) before depreciation, depletion and amortisation, share-based payment expense, exploration and appraisal costs, and impairment charges. EBITDA is a non-IFRS performance measure with no standard meaning under IFRS, and is reconciled to the income statement in note 19 to the accompanying financial information.

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

KEY PERFORMANCE INDICATORS

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

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 2012 Max Petroleum annual report:

Since we began our renewed exploration programme in 2010, Max Petroleum has changed a great deal, evolving from having a single producing field and highly prospective acreage to having multiple fields in production and a post-salt exploration programme focused on a Triassic Rim play type that has only recently been identified.

The last year has been one of achievement mixed with disappointment. We drilled 17 shallow post-salt wells and began NUR-1, a deep, pre-salt well of strategic significance for our Company and for the Republic of Kazakhstan. We made two discoveries, including the important Sagiz West Field, and approximately doubled our daily rate of production over the year. However, we ran into severe problems with NUR-1 at Emba B, as we attempted to penetrate the salt layer at approximately 5,700 metres, leading us to suspend drilling the well in July. Total costs associated with NUR-1 of approximately US$39 million, as well as a combination of other circumstances have created a significant financial challenge for the Company that we are working through currently.

Those circumstances began about a year ago with a US$14 million negative cash impact caused by the outcome of a Kazakh tax case, the loss of export oil sales due to a change in Kazakh policy, and continued with severe weather conditions that curtailed our production in early 2012. Furthermore, NUR-1 costs were greater than expected and we do not anticipate receiving any further advances from our principal lender above our current borrowings. Meanwhile, the current Kazakh regulatory environment has negatively impacted our ability to raise additional equity capital.

Faced with these challenges and an exploration period expiring in March 2013, we have been working diligently to raise needed funds, and were pleased to be able to announce an agreement with Zhanros Drilling under which we have been able to recommence our shallow drilling campaign.

We remain actively engaged with initiatives to raise additional capital on a more comprehensive basis. Our top priorities are to raise the funds necessary to complete our shallow exploration programme prior to March 2013 and to refinance, in whole or in part, our senior debt, while we continue to seek funding and an extension necessary to finish drilling NUR-1 to its target depth of 7,250 metres.

We are focused on reducing costs to reflect our impending transition from an exploration to a production oriented company, as well as our financial circumstances. At the same time, we are sensitive to the need to retain and incentivise our work force and to achieve a significant recovery of shareholder value.

As always, we remain deeply appreciative of your patience and support.

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

During the fiscal year ended 31 March 2012, Max Petroleum had success with its shallow exploration and appraisal programme and commenced the 7,250 metre NUR-1 well, its first deep, pre-salt exploration well designed to evaluate the Emba B prospect on its Blocks A&E licence area (the "Licence").

The Group's shallow drilling campaign added two post-salt discoveries out of five exploration wells and significantly expanded reserves, production, and cash flow from operations from its post-salt fields. Max Petroleum transformed from a single to a multiple, six field producer in less than one year, with four of the fields on variable test production at year-end. Production doubled during the year from approximately 2,000 bopd at the start of the year to approximately 4,000 bopd at year-end and full year production exceeded one million barrels for the first time in the Group's history. Since year-end, Group production has averaged approximately 3,900 bopd.

Applying knowledge gained from its 14 post-salt exploration wells drilled since January 2010 and 3D seismic data acquired over Western Block E, the Group high graded a portfolio of seven additional Triassic Rim prospects that it intends to evaluate, subject to financing, prior to the expiration of its exploration licence in March 2013. The seven prospects will target 67 mmbo of unrisked mean resource potential (24 mmbo risked) for a total cost of approximately US$12 million.

The Group experienced setbacks in its pre-salt exploration programme, however, as drilling of the NUR-1 well ran behind schedule, encountered mechanical problems due to anomalously high pressures while drilling through the salt section at approximately 5,700 metres, and was temporarily suspended in July 2012 pending the Group obtaining additional financing to complete the well. Max Petroleum has initiated discussions to seek regulatory approval to allow time to complete the drilling of NUR-1 beyond the end of the exploration period of the Licence, and possibly evaluate further pre-salt prospects if NUR-1 is successful.

The Group is seeking additional sources of debt or equity capital to finance the completion of its post-salt exploration programme and underpin future appraisal and development drilling activities. The Group is in discussions with its senior lender, Macquarie Bank Limited ("Macquarie"), and a number of other sources of debt and equity financing, to allow the completion of its exploration programme and to refinance, partially or fully, its senior credit facility with Macquarie and extend the maturities of its senior and convertible debt, both of which mature in 2013. The Group's recent efforts to raise equity financing have been impacted by market conditions, as well as recent regulatory changes in Kazakhstan that currently prevent the Group from completing a conventional equity offering. While it is expected these regulatory restrictions will be alleviated at some point in the near future, the timing is uncertain and the Group is looking at alternative means of raising capital in the short term. Ongoing negotiations have been constructive and the Board is hopeful it will be able to resolve the Group's current financial situation in the near future given the solid foundation of production and cash flow provided by its post-salt discoveries to date.

OUR STRATEGY

Max Petroleum's strategy is substantially 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 in both the post and pre-salt with significant existing transportation and production infrastructure. The Group has approximately 40% of its acreage covered with regional 3D seismic data, which was used to develop its existing prospect inventory.

As the Group proceeds to the end of the exploration period of the Licence in March 2013, the Board and management's principal focus is to complete the post-salt exploration programme, with an expectation of generating two to three additional discoveries, and retain the optionality to complete the NUR-1 well and evaluate the Emba B prospect at a future date. Additionally, the Group is working hard to ensure that its existing shallow discoveries transfer smoothly into the Licence's 25-year appraisal and production period. Raising additional capital and restructuring the Group's balance sheet are key parts of the equation to unlock shareholder value, and will be an ongoing focus of the Group as it works through the remainder of fiscal year 2013.

OPERATIONS REVIEW

Post-salt drilling programme

Since January 2010, the Group has drilled five discoveries out of 14 exploration wells, a success rate of 36%. To date, the Group has made six post-salt discoveries including the Zhana Makat, Borkyldakty, Uytas, Asanketken, East Kyzylzhar I, and Sagiz West fields, all of which are in various stages of testing, appraisal, or development.

During the year ended 31 March 2012, the Group drilled a total of 17 wells, including five exploration wells that led to two discoveries and 12 appraisal and development wells, of which 11 were successful. Subsequent to 31 March 2012, Max Petroleum has drilled two shallow appraisal wells, ASK-J1 and ASK-J2, in the Asanketken Field. Both wells are currently on test production. 

During the remainder of fiscal year 2013, the Group intends to drill its remaining post-salt exploration portfolio of seven prospects, and up to four appraisal and development wells at Sagiz West and Zhana Makat.

The Group's remaining post-salt exploration prospects are as follows:

In August 2012, the Group entered into a US$7 million equity for services agreement with its shallow drilling contractor, Zhanros Drilling LLP ("Zhanros"), to drill up to four post-salt wells in exchange for up to 90,322,581 ordinary shares at a price of 5p per share. The Zhanros agreement allows the Group to proceed with its shallow drilling programme at a critical time while the Group works through a broader capital restructuring.

The Group currently has one rig under contract with Zhanros that is drilling the BCHW-1 well on the Baichonas West Prospect and has awarded tenders for two additional Zhanros rigs, which can be used to complete the shallow exploration programme subject to the Group obtaining the requisite financing to drill the wells. The Group expects to generate two to three additional shallow discoveries out of its remaining post-salt prospect inventory, assuming it is able to drill the entire portfolio.

Production

During the fiscal year ended 31 March 2012, the Group produced 1,027,000 bbls, or 2,807 bopd, an increase of approximately 33% from total production of 773,000 bbls, or 2,118 bopd, in the prior year. The Zhana Makat Field continued to perform well, averaging 2,344 bopd during the year. Additionally, production commenced at five new fields, at various times throughout the year.

Kazakh regulations require each field to progress through incremental regulatory stages of appraisal and development, including the testing and appraisal phase ("Test Production"), trial production ("TPP") and then full field development ("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 may only 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 apply for and 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.

The rate of production from fields on Test Production can be highly variable due to the uncertain stabilised 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 to move a field to TPP status.

In June 2011, Borkyldakty was granted TPP status and was able to commence continuing production operations. In September 2011, Asanketken started Test Production, followed by East Kyzylzhar I in November and Sagiz West in December. Uytas was brought back onto Test Production in January 2012, following preliminary tests in early 2011. Zhana Makat was transferred from TPP to FFD status in March 2012. The Group expects both Asanketken to move to TPP status and Borkyldakty to move to FFD status in the first half of 2013, while Sagiz West, Uytas and East Kyzylzhar I are not expected to proceed to TPP until 2014 after the Group drills more appraisal wells during 2013 to gather the additional information necessary to prepare an application for TPP.

Production over the four month period from 1 April 2012 to 31 July 2012 averaged 3,900 bopd. This total was impacted by weather related issues at the beginning of the period and by the variability of production from wells on Test Production. As of August 2012, the Group was producing approximately 3,700 bopd from three fields, Zhana Makat, Borkyldakty, and Asanketken, with the other three fields shut-in due to Test Production constraints. Furthermore, Sagiz West produced high levels of associated gas, which required production rates during testing to be curtailed due to limits on gas flaring during the tests. Without regulatory restraints, the Group's current productive capacity is approximately 6,000 bopd.

Production from existing discoveries for the fiscal year ended 31 March 2013 is expected to average between 3,200 and 4,000 bopd. A substantial increase in average daily production to between 4,500 and 6,000 bopd is expected for fiscal year 2014 as Asanketken moves onto TPP and additional appraisal and development wells are drilled in Zhana Makat, Sagiz West and Uytas. The broad ranges of future production estimates are based upon the variability of wells on Test Production and timing of applicable regulatory approvals. Test Production from any successful exploration wells drilled prior to year-end would supplement both of these ranges for estimated production, as well.

Reserves and Resources

In the year ended 31 March 2012, the Group experienced substantial growth in reserves and contingent resources due to new discoveries during the year and further appraisal and analysis of existing discoveries. Given the early stage of the Group's asset base, the majority of the growth is reflected in possible reserves and contingent resources, which the Group expects to convert into proved and probable ("2P") reserves as the underlying fields are more fully appraised and developed.

As at 31 March 2012, the Group's competent person, Ryder Scott Company ("RSC"), estimated that the Group had 10.6 mmbo in 2P reserves with an after-tax net present value discounted at 10% ("PV10") of US$215 million, an increase of 36% from 7.8 mmbo in 2P as at 31 March 2011 with a PV10 of US$176 million. RSC estimated that the Group's total proved, probable and possible ("3P") reserves increased by 72% to 14.6 mmbo as at 31 March 2012, with a PV10 of US$285 million, from total 3P reserves in the prior year of 8.5 mmbo, with a PV10 of US$194 million.

As at 31 March 2012, RSC estimated the Group's oil-initially-in-place ("OIIP") for the Sagiz West and Uytas fields, the Group's two largest discoveries to date, of 101.3 mmbo and 64.9 mmbo, respectively, of which 79.8 mmbo and 27.2 mmbo were classified as in-place contingent resources. The Group has internally estimated an additional 126 mmbo in non-conventional resources 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. The Group did not have any reserves or resources booked for either field as of 31 March 2011.

The Group reported total 2P reserves as at 30 September 2011 of 13.3 mmbo, as well as in-place contingent resources at Sagiz West of 61.3 mmbo. The 2P estimate included 4.8 mmbo in reserves based on the initial well drilled in the Sagiz West Field in September 2011. In December 2011, the Group drilled a second well in the Sagiz West Field, SAGW-2, that was non-productive and reduced the productive area of the eastern flank of the field from original estimates. The third well, SAGW-3, drilled in February 2012, was successful in confirming the discovery and supporting the Group's view of the field's overall size and structure. Given the results of SAGW-2 and the greater complexity of the field, however, the estimate for 2P reserves for Sagiz West was adjusted downward as of 31 March 2012 by 2.2 mmbo, while in-place contingent resources for the field increased by 18.5 mmbo. Other changes in the estimate of 2P between the periods relate primarily to production and the revision of reserve estimates based on well performance and estimated recovery factors.

A table showing the Group's reserves and resources as calculated by RSC for the years ended 31 March 2012 and 31 March 2011, and the interim period ended 30 September 2011 is presented below:

Zhana Makat Field

The Zhana Makat Field, discovered in September 2006, continues to perform well, with average daily production of approximately 2,300 bopd for the year ended 31 March 2012 from a combination of Jurassic, Neocomian, and Triassic reservoirs. The field commenced commercial production under TPP in August 2007, with cumulative sales of 3.6 mmbo generating US$211 million in total revenue through 31 March 2012. Zhana Makat was approved for FFD status in March 2012, allowing the Group to continue to develop and produce the field for up to 25 years, as well as giving it a right to sell up to 80% of its crude oil production on the export market under the terms of the Licence. The Group drilled five exploration, appraisal and development wells in the field in fiscal year 2012, including two Triassic wells in the southern end of the field that were subject to 90-day Test Production constraints given the exploratory nature of the wells. The Group expects to return the Triassic wells to production under the field's FFD permit in 2013 upon receipt of the necessary regulatory approvals. The Group also plans to drill up to eight additional appraisal and development wells over the next 12 months under FFD.

Borkyldakty Field

The Borkyldakty Field was discovered in Block E in February 2010, with the BOR-1 well encountering five productive Triassic reservoirs in a small four-way anticlinal structure. In June 2011, the Group received regulatory approval of Borkyldakty's TPP, allowing the Group to place the field on continuous production and drill further exploration and appraisal wells, if necessary, in order to gather additional data needed to proceed to FFD status. In July 2011, the Group successfully drilled and completed the BOR-3 appraisal well, encountering 28 metres of net oil pay over five Triassic sandstone reservoirs and has one additional drilling location planned in 2013. The Group expects to obtain FFD status during the first half of 2013.

Uytas Field

The Uytas Field, a shallow, four-way anticline with productive Cretaceous and Jurassic reservoirs, was discovered in Block A in October 2010. Drilled to a depth of 827 metres, the UTS-1 discovery well potentially makes Uytas the Group's largest post-salt discovery to date. Uytas is a unique field given its shallow depth, with productive Cretaceous reservoirs above 160 metres and Jurassic reservoirs between 300 and 400 metres.

Interpretation of 3D seismic data acquired in late 2011 revealed a structure larger than previously identified which enabled the Group's estimate of OIIP to increase to 184 mmbo, including 58 mmbo in conventional Cretaceous Aptian ("Aptian") and Jurassic reservoirs and 126 mmbo in shallower, non-conventional Cretaceous Albian ("Albian") reservoirs. RSC estimates are in line with this assessment, estimating OIIP of 65 mmbo for the conventional Aptian and Jurassic reservoirs as of 31 March 2012, of which 27 mmbo are classified as contingent resources in-place. The Group has internally estimated an additional 126 mmbo in non-conventional resources at Uytas from the 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 shown to be recoverable through a pilot production test.

Well tests have confirmed commercial productivity from the Aptian and Jurassic sandstone reservoirs, with Phase One of an appraisal and development programme expected to include approximately 30 low-cost, shallow vertical wells with 14 wells planned to be drilled in 2013, subject to financing. The Group anticipates up to 200 shallow vertical wells will eventually be drilled in the field to develop its conventional reserves, over a period of several years. Based on testing and core analysis, the Group is also planning an enhanced oil recovery pilot project using steam injection to determine the commerciality of the Albian reservoirs.

The OIIP estimates from RSC provide external confirmation of the significant size of the field. Further appraisal drilling and more production history from existing and future wells is expected to lead to much higher recoverable reserves and a higher assumed recovery factor for the field by RSC. The Group expects Uytas to move into TPP during 2014 after the Group has completed the Phase One appraisal drilling programme and the pilot project to evaluate the non-conventional Albian reservoirs.

 Asanketken Field

The Asanketken Field was discovered in March 2011 with the ASK-1 well encountering 24 metres of net oil pay at depths from 1,230 to 1,302 metres in the Jurassic formation in a three-way faulted trap. The ASK-2 well confirmed the Jurassic discovery at the end of 2011, while the field's deeper Triassic objective was found to be non-productive. The Group drilled two additional Jurassic appraisal wells in the field during the quarter ended 30 June 2012, both of which are currently on Test Production.

The Asanketken Field is estimated by RSC to have in-place reserves of approximately eight mmbo, with reservoirs of excellent quality from which the Group expects ultimate recovery factors of approximately 35% to 40%. Certain zones in the ASK-1 well produced at rates in excess of 1,000 bopd, and the field is currently producing approximately 1,500 bopd from three of the four wells currently on Test Production (ASK-2, ASK-J1, and ASK-J2).

The Group expects that the Asanketken Field will progress to TPP during the first half of 2013, thereby allowing continuous production from the field. FFD is expected to follow in 2014. No additional drilling is expected in the field prior to reaching FFD status. The expected rapid progress of Asanketken through the regulatory approval process is a result of the uncomplicated nature of the field and as it has already been fully appraised by the current producing wells.

East Kyzylzhar I Field

The East Kyzylzhar I Field, a three-way faulted closure located in Block E, was discovered in August 2011, with the KZIE-1 exploration well encountering 17 metres of net oil pay in two Jurassic sandstone reservoirs at depths ranging from 987 to 1,251 metres. The KZIE-2 appraisal well was drilled later in 2011, confirming the discovery. Reservoir quality is excellent with porosities ranging from 20% to 30%. The Group placed both wells on Test Production with very high initial production rates, but water cut increased rapidly in both wells. Further testing of these wells is planned later this year to determine if the water cut has been caused by a mechanical problem in the wells, as is indicated by the electric logs and other pressure data currently available. If the water production problem can be resolved, the field will move on to TPP during 2013 and the Group plans to acquire additional 3D seismic and drill additional development wells over the next several years. If not, then the field may be abandoned. The decrease in RSC 2P reserves from 30 September 2011 reflects the uncertainty of the source of the water production seen in the first two wells.

Sagiz West Field

The SAGW-1 exploration well made the initial discovery of the Sagiz West Field in Block E in September 2011, reaching a depth of 1,406 metres with electric logs indicating 27 metres of net pay, including 21 metres of oil and 6 metres of gas pay, over a 114 metre interval in the Triassic formation at measured depths between 1,177 and 1,291 metres. Reservoir quality is very good with porosities ranging from 18% to 25%. The unsuccessful SAGW-2 appraisal well did not encounter producible hydrocarbons, limiting the eastern flank of the field. However, the SAGW-3 appraisal well confirmed the initial discovery and Group's view of the large potential size and scope of the field.

As of 31 March 2012, RSC estimated 2P reserves for Sagiz West of 2.6 mmbo and contingent resources in-place of approximately 79.8 mmbo. The 2P estimate was adjusted downward by RSC from 30 September 2011 due to the results of SAGW-2 and the greater complexity of the field, but their higher estimate of contingent resources supports the Group's view that Sagiz West has potential ultimate recoverable reserves of between 15 and 20 mmbo. The Group expects ultimate recovery factors for the field to range from 20% to 30%.

Subject to available financing, the Group is planning to acquire additional infill 3D seismic data over the field prior to 31 December 2012, and drill a fourth appraisal well, SAGW-4, in early 2013 in order to extend the field substantially further south. Development of the field will require the processing and sale of associated natural gas, and while this adds to the cost and time to develop the field, revenues from potential gas sales are expected to more than offset the additional facilities required to process the gas and deliver it to market. The associated gas is also expected to improve oil recoverability in the field.

The Group is also planning to drill up to 10 additional wells in Sagiz West during 2013, subject to financing, to appraise the field and gather enough information to design and build the field facilities required to handle the associated gas production expected when Sagiz West enters TPP. Due to the need for further appraisal drilling, and the amount of time needed to design and construct the production facilities required for TPP, the estimated start of TPP has been moved out into 2014. The Sagiz West Field is currently shut-in pending drilling additional wells that will be placed on Test Production before moving these and existing wells onto TPP.

Both the SAGW-1 and SAGW-3 wells have additional zones which will ultimately be tested, including lower porosity oil reservoirs in both wells that may respond well to hydraulic fracturing and a possible gas cap in SAGW-1. Further testing is expected to demonstrate additional value both from increased oil production and potential gas sales, but will not yield significant production in the near term and is currently being planned for during the appraisal drilling programme in 2013. 

Pre-salt potential

On 4 November 2011, the Group began drilling the NUR-1 well on the Emba B prospect in Block E. The well had a target depth of 7,250 metres and targeted reservoirs with unrisked mean resource potential of 467 million barrels of oil equivalent with a 29% geological chance of success.

On 5 April 2012, the NUR-1 well reached the top of the Kungurian salt at a depth of 5,718 metres. However, upon drilling into the salt a high pressure transition was encountered resulting in the drilling tools becoming stuck. After side-tracking the well and setting casing at 5,681 metres, the Group drilled ahead. Progress was slow as the Group drilled alongside the stuck drilling tools. After clearing the old wellbore, the well reached the Kungurian salt on 19 June 2012. Due to encountering anomalously high pressures beyond the scope of the original well design, the drill pipe again become stuck at 5,722 metres, despite using the higher density mud specified for penetrating this section. The Group was unable to free the stuck drill string and decided to suspend drilling operations and release the drilling rig in July given the need to obtain additional capital to complete the well.

Based on a review conducted by the Group's in-house technical team and external consultants with expertise in drilling high pressure, pre-salt wells, the Group believes it is technically feasible to complete the drilling of NUR-1 with certain modifications to the existing drilling programme to address the higher than expected pressures encountered in the salt. The Group is currently considering options to finance independently the completion of the well and has commenced discussions with the relevant Kazakh Government authorities to seek regulatory approval to allow completion of the drilling of NUR-1 beyond the existing deadline in March 2013.

The NUR-1 pre-salt well has been drilled and cased down to a depth of 5,681 metres. Subject to financing being obtained to complete this well, and an extension beyond the current 4 March 2013 date of expiry of the exploration period of the Licence, the Group intends to bring in another rig and finish testing the well down to its total depth of 7,250 metres. Preliminary discussions with the Kazakh regulatory authorities regarding an extension due to the unexpected high pressures encountered in NUR-1 have been constructive. The Group is continuing to work with external experts to establish how best to deal with this pressure on a resumption of drilling and how, in cooperation with the authorities, to best redesign the well so as to successfully drill through the Kungurian salt layer. Given that the well has been successfully drilled down to the current depth, a broader range of rigs fit the criteria required and would be available. The Group has incurred a total of approximately US$39 million on NUR-1 and estimates it will require between US$12 and 20 million in additional capital in order to finish drilling the well to its target depth at a later date.

Results of operations

The Group recognised a loss of US$8.2 million, or US$0.01 per ordinary share, for the year ended 31 March 2012, compared to a loss of US$18.2 million, or US$0.04 per ordinary share, during the prior year.

Oil sales volumes increased by 32% compared to the previous year to reach 1,004,000 bbls compared to 760,000 bbls in the previous year. The Group produced and sold 1,004,000 bbls during 2012, comprising 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. Comparatively, the Group produced and sold 760,000 bbls during 2011, including 154,000 bbls sold into the domestic market generating US$5.7 million in revenue, or US$36.74 per bbl, and 606,000 bbls sold into the export market generating US$49.7 million in revenue, or US$81.93 per bbl. Oil revenues decreased by 9% from US$55.3 million in 2011 to US$50.2 million in 2012, as the average price per barrel decreased from US$72.78 to US$50.04 as substantially all of the Group's sales during the year were domestic. Exports of oil produced at Zhana Makat resumed following FFD approval, which have contributed to higher average sales prices per barrel since then.

Net cash generated from operating activities increased by 29% from US$14.4 million for the year ended 31 March 2011 to US$18.6 million for the year ended 31 March 2012, while cash flow from operating activities before income taxes for the comparable periods increased by 70% from US$16.7 million to US$28.3 million, primarily based on higher sales volumes and an increase in prepayments from domestic customers in Kazakhstan for crude oil sales.

The Group incurred US$4.4 million in exploration and appraisal costs written-off during the current year compared to US$7.0 million in 2011.

During the year ended 31 March 2012, the Group incurred total administrative expenses of US$17.8 million, compared to administrative expenses of US$15.0 million in 2011. 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$4.9 million in the year ended 31 March 2012, compared to US$1.8 million in 2011.

Changes in crude oil marketing: domestic versus export

In May 2011, following correspondence and discussions with local regulatory authorities, Max Petroleum began selling 100% of its crude oil production from Zhana Makat on the domestic market pending FFD approval for the field, which was granted on 15 March 2012. Prior to May 2011, the Group had exported 80% of its crude oil production from Zhana Makat. FFD approval gives the Group the right to sell 80% of its crude oil production from the Zhana Makat Field on the export market under the terms of its Blocks A&E Licence. Similarly, production from the Group's other more recent discoveries will be sold exclusively on the domestic market until each field is approved for FFD, after which the Group will have the right to sell up to 80% of its production from that field on the export market. During the year ended 31 March 2012, the Group estimates the after-tax net proceeds from sales into the domestic market ranged from US$10 to 20 per barrel lower than comparable export sales. Following FFD approval, the Group has recommenced export oil sales from Zhana Makat, which have generated after-tax net proceeds that are on average US$16 per barrel higher than comparable domestic sales.

Tax claim

During the year ended 31 March 2012, the Group paid US$13.8 million in full settlement of a tax claim brought against the Group by the local tax authorities of the Republic of Kazakhstan (the "Tax Claim") with the aggregate costs of the Tax Claim totalling US$18.8 million for fiscal years ended 31 March 2011 and 2012.

The Tax Claim resulted from a routine tax audit of the Group's entities in Kazakhstan for calendar years 2005 to 2008 and involved a dispute over the timing of recovery (i.e. depreciation) of the Group's costs capitalised to its oil and gas properties for tax years prior to Kazakhstan's adoption of the new Tax Code in 2009. In summary, the Group began depreciating its capitalised costs when it began producing crude oil in accordance with the terms of its subsoil use licence and the Kazakh legislation in place at the time the licence was executed. The local tax authorities, however, asserted that the Group should only begin depreciating its capital costs upon the formal declaration of a commercial discovery to the Kazakh authorities. As a result, the local tax authorities disallowed a total of US$35 million in depreciation deductions taken by the Group during calendar years 2006 through 2008. The Group expects to recover the economic benefit of the deductions in future years.

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 Macquarie Bank Limited (the "Credit Facility"), and additional debt or equity financing as required. The Group is in the last year of the exploration period of its Licence and requires approximately US$10 to 15 million in additional exploration and appraisal capital for its shallow programme through March 2013, as well as additional capital for the future appraisal and development of its current and expected post-salt discoveries beyond fiscal year 2013.

The Group is currently producing approximately 3,700 bopd generating approximately US$7 to 8 million per month in pre-tax revenue and significant net cash flow from operations, which is being applied in the near-term against trade payables relating to its exploration and appraisal activities and will be available to begin repaying borrowings under the Credit Facility in the medium term. The Group currently has limited or no additional borrowing capacity available under the Credit Facility. As of 15 August 2012, the Group had borrowed a total of US$55.2 million under the Credit Facility, including a US$3 million letter of credit. The Credit Facility matures on 31 March 2013 and requires that the Group begin making amortisation payments of US$2 million per month beginning in July 2012. The Group did not make an amortisation payment in July 2012 and is in ongoing discussions with Macquarie regarding the use of its net cash flow from operations to fund its shallow drilling activities, as well as the timing and amount of principal payments required prior to 31 March 2013.

Although the ongoing discussions with Macquarie have been constructive, the Group does not anticipate that additional borrowings or deferred principal payments under the Credit Facility will be available to fund its remaining shallow exploration programme. As a result, the Group is in discussions with various sources of debt and equity capital, including several operating oil and gas companies, to provide financing to finish its shallow exploration portfolio, as well as to refinance, in whole or in part, the Credit Facility.

The Group also has US$85.6 million in Convertible Bonds that mature on 8 September 2013 and require semi-annual interest payments of US$2.9 million on 8 September and 8 March, respectively. The Group intends to restructure the terms of the Bonds in conjunction with any future refinancing of the Credit Facility. The Group has obtained written assurances from holders representing greater than 75% of the Bonds to defer the coupon payment due 8 September 2012 until 8 December 2012 pending a broader restructuring of the Group's outstanding debt.

In August 2012, the Group entered into a US$7 million equity for services agreement with Zhanros Drilling LLP, whereby Zhanros will drill up to four post-salt wells and fund related ancillary services in exchange for up to 90,322,581 ordinary shares at a price of 5p per share. While the Zhanros agreement does not inject any direct liquidity into the Group, it will allow for a portion of the shallow exploration portfolio to be drilled and assist in the Group's efforts to complete a broader capital restructuring.

The Group's efforts to raise traditional equity capital in the near term have been hampered by recent regulatory changes in the Republic of Kazakhstan that require the Company to list on the Kazakhstan Stock Exchange ("KASE") in order to obtain the regulatory consents necessary to conduct a traditional equity placement or rights offering. The Group understands that the KASE eligibility criteria are under review and may be amended in the near future such that the Company would be eligible to list on KASE, but the timing and ultimate resolution of this issue is uncertain.

Although the directors are working to resolve the Group's outstanding liquidity shortfall, there is an uncertainty that the Group will be able to extend or restructure the Credit Facility or its Convertible Bonds, or that additional debt or equity financing will be available. They have concluded that this factor, together with the other matters referred to above, results in the existence of a material uncertainty that may cast a significant doubt about the Group's ability to continue as a going concern. Nevertheless, based on its current production and net cash flow from operations, ongoing discussions with Macquarie, Bondholders, and other potential sources of debt and equity capital, the directors have a reasonable expectation that the Group will continue in operational existence for the foreseeable future.

Based on their short-term cash forecasts, the directors believe that the combination of these factors will provide sufficient working capital to enable the Group to continue trading and remain solvent. However, these forecasts are necessarily based on the achievement of timing and targets some of which, although believed to be reasonable by the directors, are nevertheless outside the Group's direct control. If significant delays or underperformance of production or revenue targets were to take place, these may render the Group's cash resources insufficient.

RISK FACTORS

The Group is subject to various risks relating to political, economic, legal, social, industry, business and financial conditions. The following risk factors, which are not exhaustive, are particularly relevant to the Group's business activities:

Volatility of prices for oil and gas

The supply, demand and prices for oil and gas are volatile and are influenced by factors beyond the Group's control. These factors include global demand and supply, exchange rates, interest and inflation rates and political events. A significant prolonged decline in oil and gas prices could impact the viability of some of the Group's exploration activities. Additionally, production from geographically isolated countries may be sold at a discount to current market prices.

Substantially all of the Group's revenues and cash flows will come from the sale of oil and gas. If oil and gas prices should fall below and remain below the Group's cost of production for any sustained period, the Group may experience losses and may be forced to curtail or suspend some or all of its production, at the time such conditions exist. In addition, the Group would also have to assess the economic impact of low oil and gas prices on the its ability to recover any losses it may incur during that period and on its ability to maintain adequate reserves.

While the Group does not currently hedge its crude oil production to reduce its exposure to oil price volatility, management expects that it may do so in the future as it increases its daily production sold into the export market. The Group would enter into price hedging contracts in order to achieve more predictable cash flows from its future crude oil production and to comply with the terms of its Credit Facility, if applicable.

Exploration risk

The exploration for, and the development of, hydrocarbons is speculative and involves a high degree of risk. These risks include the uncertainty that the Group will discover sufficient oil or gas resources to exploit economically or that the Group will be able to exploit the discovered resource as intended. Drilling may not result in the discovery of economically viable hydrocarbon resources either due to insufficient resources being discovered, the resources not being of sufficient quality to be developed economically or the cost of any development being in excess of that required for an economic project. Furthermore, there is a risk the Group may be unable to complete the drilling of its remaining exploration portfolio prior to the expiry of the exploration period of its Licence in March 2013.

Environmental risk

The oil and gas industry is subject to environmental hazards, such as oil spills, gas leaks, ruptures and discharges of petroleum products and hazardous substances. These environmental hazards could expose the Group to material liabilities for property damages, personal injuries, or other environmental harm, including costs of investigating and remediating contaminated properties. The Group is subject to stringent environmental laws in the Republic of Kazakhstan with regard to its oil and gas operations. Failure to comply with such laws and regulations could subject the Group to material administrative, civil, or criminal penalties or other liabilities. Additionally, compliance with these laws may, from time to time, result in increased costs to the Group's operations, impact production, or increase the costs of potential acquisitions. The Group was compliant with all material environmental and health and safety laws during the year.

Risk of operating oil and gas properties

The oil and gas business involves certain operating hazards, such as well blowouts, cratering, explosions, uncontrollable flows of oil, gas or well fluids, fires, pollution, and releases of toxic substances. Any of these operating hazards could cause serious injuries, fatalities, or property damage, which could expose the Group to liabilities. The settlement of these liabilities could materially impact the funds available for the exploration and development of the Group's oil and gas properties. The Group maintains insurance against many potential losses and liabilities arising from its operations in accordance with customary industry practices, but the Group's insurance coverage cannot protect it against all operational risks.

Foreign currency risk

The Group's operating costs, export revenues, and debt financing facilities are principally denominated in US dollars. The Group's UK Plc office costs and share consideration are in British pounds. Also, some costs are incurred and settled in tenge, the local currency of the Republic of Kazakhstan. Any changes in the relative exchange rates among US dollars, tenge and British pounds could positively or negatively affect the Group's results.

Business in Kazakhstan

Amongst the risks that face the Group in conducting business and operations in Kazakhstan are:

·; Economic instability, including in other countries or the global economy that could lead to consequences such as hyperinflation, currency fluctuations and a decline in per capita income in the Kazakh economy.

·; Insufficient or underdeveloped physical infrastructure.

·; Governmental and political instability that could disrupt, delay or curtail economic and regulatory reform, increase centralised authority or result in nationalisation.

·; Social instability from any ethnic, religious, historical or other divisions that could lead to a rise in nationalism, social disturbances or conflict.

·; Uncertainties in the developing legal and regulatory environment, including, but not limited to, conflicting laws, decrees and regulations applicable to the oil and gas industry and foreign investment.

·; Unlawful or arbitrary action against the Group and its interests by the regulatory authorities, including the suspension or revocation of its Licence or failure to approve extensions or other permits necessary for the Group to continue operating its assets.

·; Lack of independence and experience of the judiciary, difficulty in enforcing court or arbitration decisions and governmental discretion in enforcing claims.

·; Laws restricting foreign investment in the oil and gas industry.

·; Regulations which include pre-approval from the National Bank of Kazakhstan for the issuance of equity, as well as obtaining a pre-emption waiver from the Ministry of Oil and Gas.

Taxation

The tax environment in Kazakhstan is subject to regular change and varying interpretations. As the tax law evolves, instances of inconsistent opinions between local, regional and national tax authorities are not unusual. Non-compliance with laws and regulations in Kazakhstan, as interpreted by the Kazakh authorities, may lead to severe penalties and interest which can amount to multiples of any assessed taxes. The uncertainty of interpretation and application of tax laws, which are subject to regular change, creates a risk that the ultimate amount of taxes, penalties and interest, if any, may be in excess of the amounts recognised to date, which could have a material adverse impact on the Group's cash flows, results and financial position. Management believes that it is in compliance with the relevant legislation affecting its operations, and that its tax affairs are appropriately accounted for in these financial statements.

Legal systems

Kazakhstan, and other countries in which the Group may transact business in the future, have or may have legal systems that are less well developed than in the United Kingdom. This could result in risks such as:

·; Potential difficulties in obtaining effective legal redress in the courts of such jurisdictions, whether in respect of a breach of contract, law or regulation, including an ownership dispute.

·; A higher degree of discretion on the part of government authorities.

·; The lack of judicial or administrative guidance on interpreting applicable rules and regulations.

·; Inconsistencies or conflicts between and within various laws, regulations, decrees, orders and resolutions.

·; Relative inexperience of the judiciary and courts in such matters.

In certain jurisdictions, the commitment of local business people, government officials and agencies and the judicial system to abide by legal requirements and negotiated agreements may be more uncertain, creating particular concerns with respect to licences and agreements for business. These may be susceptible to revision or cancellation and legal redress may be uncertain or delayed. There can be no assurance that joint ventures, licences, licence applications or other legal arrangements will not be adversely affected by the jurisdictions in which the Group operates.

Liquidity risk

Liquidity risk is the risk that the Group will not be able to meet its financial obligations as they fall due. The Group's approach to managing its liquidity is to ensure, as far as possible, that it will always have sufficient liquid funds and available debt and equity capital to meet its liabilities when due, without incurring unacceptable losses or risking damage to the Group's reputation.

The Group has prepared cash flow forecasts for the twelve months from the date of signing of these financial statements which indicate that it will need additional financing in order to carry out its post-salt drilling programme ahead of the expiry of the exploration phase of its Licence in March 2013, fund administrative and operating expenses, and service its Credit Facility and Bonds. The Group is working with its senior lender, Macquarie, and has initiated discussions with a number of providers of debt and equity financing, regarding the provision of additional capital.

The Group carefully monitors and manages its liquidity with regular cash forecasting. Further details of the Group's liquidity position are set out in the liquidity and capital resources section of the Business Review.

MAX PETROLEUM PLC

CONSOLIDATED AND COMPANY INCOME STATEMENTS

For the year ended 31 March 2012

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED AND COMPANY STATEMENTS OF COMPREHENSIVE INCOME

For the year ended 31 March 2012

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED AND COMPANY BALANCE SHEETS

At 31 March 2012

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 March 2012

(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 2012

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED AND COMPANY CASH FLOW STATEMENTS

For the year ended 31 March 2012

(in thousands of US$)

MAX PETROLEUM PLC

NOTES TO THE FINANCIAL INFORMATION

For the year ended 31 March 2012

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 and quoted on AIM. 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 2012 or 2011, but it is derived from those accounts. Statutory accounts for 2011 have been delivered to the Registrar of Companies and those for 2012 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, contains an emphasis of matter which draws 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 2011 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 (see note 11), and additional debt or equity financing as required. The Group is in the last year of the exploration period of its Licence and requires approximately US$10 to 15 million in additional exploration and appraisal capital for its shallow programme through March 2013, as well as additional capital for the future appraisal and development of its current and expected post-salt discoveries beyond fiscal year 2013.

The Group is currently producing approximately 3,700 bopd generating approximately US$7 to 8 million per month in pre-tax revenue and significant net cash flow from operations, which is being applied in the near-term against trade payables relating to its exploration and appraisal activities and will be available to begin repaying borrowings under the Credit Facility in the medium term. The Group currently has limited or no additional borrowing capacity available under the Credit Facility. As of 15 August 2012, the Group had borrowed a total of US$55.2 million under the Credit Facility, including a US$3 million letter of credit. The Credit Facility matures on 31 March 2013 and requires that the Group begin making amortization payments of US$2 million per month beginning in July 2012. The Group did not make an amortisation payment in July 2012 and is in ongoing discussions with Macquarie regarding the use of its net cash flow from operations to fund its shallow drilling activities, as well as the timing and amount of principal payments required prior to 31 March 2013.

Although the ongoing discussions with Macquarie have been constructive, the Group does not anticipate that additional borrowings or deferred principal payments under the Credit Facility will be available to fund its remaining shallow exploration programme. As a result, the Group is in discussions with various sources of debt and equity capital, including several operating oil and gas companies, to provide financing to finish its shallow exploration portfolio, as well as to refinance, in whole or in part, the Credit Facility.

The Group also has US$85.6 million in Bonds that mature on 8 September 2013 and require semi-annual interest payments of US$2.9 million on 8 September and 8 March, respectively. The Group intends to restructure the terms of the Bonds in conjunction with any future refinancing of the Credit Facility. The Group has obtained written assurances from holders representing greater than 75% of the Bonds to defer the coupon payment due 8 September 2012 until 8 December 2012 pending a broader restructuring of the Group's outstanding debt.

In August 2012, the Group entered into a US$7 million equity for services agreement with Zhanros Drilling LLP, whereby Zhanros will drill up to four post-salt wells and fund related ancillary services in exchange for up to 90,322,581 ordinary shares at a price of 5p per share. While the Zhanros agreement does not inject any direct liquidity into the Group, it will allow for a portion of the shallow exploration portfolio to be drilled and assist in the Group's efforts to complete a broader capital restructuring.

The Group's efforts to raise traditional equity capital in the near term have been hampered by recent regulatory changes in the Republic of Kazakhstan that require the Company to list on the Kazakhstan Stock Exchange ("KASE") in order to obtain the regulatory consents necessary to conduct a traditional equity placement or rights offering. The Group understands that the KASE eligibility criteria are under review and may be amended in the near future such that the Company would be eligible to list on KASE, but the timing and ultimate resolution of this issue is uncertain.

Although the directors are working to resolve the Group's outstanding liquidity shortfall, there is an uncertainty that the Group will be able to extend or restructure the Credit Facility or its Bonds, or that additional debt or equity financing will be available. They have concluded that this factor, together with the other matters referred to above, results in the existence of a material uncertainty that may cast a significant doubt about the Group's ability to continue as a going concern. Nevertheless, based on its current production and net cash flow from operations, ongoing discussions with Macquarie, Bondholders, and other potential sources of debt and equity capital, the directors have 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.

Based on their short-term cash forecasts, the directors believe that the combination of these factors will provide sufficient working capital to enable the Group to continue trading and remain solvent. However, these forecasts are necessarily based on the achievement of timing and targets some of which, although believed to be reasonable by the directors, are nevertheless outside the Group's direct control. If significant delays or underperformance of production or revenue targets were to take place, these may render the Group's cash resources insufficient.

4. Operating segments

Management has determined its operating segments based on the reports reviewed by the directors for 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$30.5 million which arose from the Group's largest customer (2011: sales to Group's largest customer of US$49.7 million).

Non-current assets

The Group's non-current 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$18.7 million (2011: US$16.1 million).

6. Finance costs

Interest payable on the Bonds for the year ended 31 March 2011 included US$4.0 million in relation to the fair value of the warrant exercisable into 30 million ordinary shares which vested as a result of the Company's election to defer convertible bond cash interest due on 8 September 2010 (see note 15).

Other finance costs include interest of US$0.3 million (2011: US$1.6 million) payable to the tax authorities of the Republic of Kazakhstan in relation to the Tax Claim brought against the Group (see note 7). Other finance costs for the year ended 31 March 2011 also included a loss on settlement of a forward foreign exchange contract of US$0.5 million.

Interest expense of US$9.0 million (2011: US$9.8 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 11% (2011: 15%) to the average cumulative expenditure on such assets. The borrowing costs capitalised are included in 'additions' to intangible assets - exploration and appraisal expenditure.

7. 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 Group and Company have generated recurring net operating losses and no deferred tax assets have been recognised with respect to such losses.

The tax on the Group's loss before tax differs from the theoretical amount that would arise using the UK statutory rate of 26% (2011: 28%) 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 26% (2011: 28%) applicable to the loss of the Company, as follows:

Tax Claim

During the year ended 31 March 2012 the Group paid US$13.8 million in full settlement of a tax claim brought against the Group by the local tax authorities of the Republic of Kazakhstan (the "Tax Claim").

The Tax Claim resulted from a routine tax audit of the Group's entities in Kazakhstan for calendar years 2005 to 2008 and involved a dispute over the timing of recovery (i.e. depreciation) of the Group's costscapitalised to its oil and gas properties for tax years prior to Kazakhstan's adoption of the new Tax Code in 2009. In summary, the Group began depreciating its capitalised costs when it began producing crude oil in accordance with the terms of its subsoil use licence and the Kazakh legislation in place at the time the Licence was executed. The local tax authorities, however, asserted that the Group should only begin depreciating its capital costs upon the formal declaration of a commercial discovery to the Kazakh authorities. As a result, the local tax authorities disallowed a total of US$35 million in depreciation deductions taken by the Group during calendar years 2006 through 2008.

Including amounts paid in previous years towards the Tax Claim, in aggregate US$18.8 million has been settled, comprising US$9.9 million of income taxes, penalties of US$4.9 million and interest of US$4.0 million.

The Group had previously fully provided for the Tax Claim in the financial statements for the years ended 31 March 2011 and 31 March 2010.

The final legal appeal to review the Tax Claim was rejected by the Supervisory Panel of the Supreme Court of the Republic of Kazakhstan during the current year. The Group expects to recover the majority of the economic value of the Tax Claim through subsequent depreciation deductions that will offset future taxable income.

8. Loss for the year

Loss for the year is stated after charging:

Exploration and appraisal costs for the year ended 31 March 2011 are presented net of US$2.0 million proceeds from the disposal of Alga Caspiygas LLP.

9. Intangible assets - exploration and appraisal expenditure

Included within exploration and appraisal expenditures at 31 March 2012 was a decommissioning asset of US$0.4 million (2011: US$0.2 million). At 31 March 2012, the Group had entered into contractual commitments for the acquisition of intangible assets amounting to US$1.4 million (2011: US$1.8 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.

The net book value of exploration and appraisal expenditure at 31 March 2012 includes US$27.0 million directly relating to the NUR-1 pre-salt well (2011: US$0.3 million). The Group suspended drilling of NUR-1 and released the rig in July 2012, see note 17.

Astrakhanskiy Licence

In January 2011, the Group relinquished control of the Astrakhanskiy Licence to the Ministry of Oil and Gas of the Republic of Kazakhstan after failing to comply with the work obligations stipulated under the licence and therefore, recorded a disposal of the related assets during the year ended 31 March 2011. The Group had previously recorded a charge of US$116.2 million to impair the related assets to US$nil during the year ended 31 March 2010, including US$115.1 million classified as exploration and appraisal assets.

10. Oil and gas properties

Included within oil and gas properties at 31 March 2012 was a decommissioning asset of US$1.1 million (2011: US$0.2 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 2012, 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 2012. The results of the comparison indicate that the discounted future net income from extracting the Group's proved and probable reserves significantly exceed the book value of the assets.

In estimating the expected recoverable amount of its producing fields, forecast production rates were based on historical performance from wells now on production. Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. An estimated rate of decline was then applied to the depletion of reserves. 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 2033, where prices per barrel range from US$94 to US$123. The domestic sales price estimates commence at US$53/bbl in 2012 and are escalated at 2% annually. The discount rate used was 10%.

11. Borrowings

Bank borrowings

In June 2007, the Group entered into a US$100 million revolving mezzanine Credit Facility (the "Credit Facility") with Macquarie Bank Limited ("Macquarie"). The material provisions of the Credit Facility are as follows:

·; Interest payable monthly at LIBOR plus 6.5%.

·; Principal repayments commence on 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.

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

The fair value of the floating rate bank borrowings at 31 March 2012 approximates to their gross carrying value of US$50.2 million (2011: US$6.0 million).

At 31 March 2012, the Group was in breach of its banking covenants relating to certain financial ratios.

At 31 March 2012, the Credit Facility had a total borrowing base of US$58.0 million available through 30 June 2012, of which US$50.2 million was borrowed and a further US$3.0 million was reserved for outstanding letters of credit.

Convertible bonds

Max Petroleum completed an offering of convertible bonds on 8 September 2006 (the "Bonds"), raising a total of US$75 million before issuance costs. Cash interest payments due on 8 March 2009, 8 September 2009 and 8 September 2010 were deferred and converted into additional principal (i.e. payment in kind or "PIK"), resulting in a revised principal of US$85.6 million.

The Bonds bear interest at 6.75% per annum, payable semi-annually, and are convertible at a price of 32p per ordinary share, with a fixed exchange rate of US$1.49 to £1. The Bondholders have a right to convert the Bonds through to final maturity on 8 September 2013. Furthermore, the holders will have certain rights to force the Company to redeem the Bonds if certain material events of default occur such as revocation of the Group's Licence to its oil and gas properties in Kazakhstan. The Group has the right to redeem the Bonds if the Bonds trade at an average price of 130% of the conversion price for a minimum of 20 out of 30 consecutive trading days or if at any time a minimum of 85% of the Bonds have been converted.

Amendments to the Bonds in May 2009 were deemed to be a substantial modification, triggering a debt extinguishment and recognition of new debt under the requirements of IAS 39 Financial Instruments: Recognition and Measurement.

Following the debt extinguishment, the fair value of the Bonds was estimated and allocated between long-term debt and equity. The additional principal arising from the interest PIKs occurring on 8 September 2009 and 8 September 2010 were also allocated between long-term debt and equity. The long-term debt component is measured at amortised cost using an effective interest rate of 11%. The option to convert interest into PIK was for two years and expired on 8 September 2010.

Movements in the Bonds during the year are analysed as follows:

1 On initial recognition, the equity component of the convertible bond is booked as a bond discount, which is subsequently amortised over the maturity of the Bonds using the effective interest rate.

The fair value of the Bonds at 31 March 2012 and 2011, determined by reference to the published closing price quotation from the Channel Islands Stock Exchange on that date, was as follows:

Interest expense

During the year ended 31 March 2012, the Group incurred US$11.1 million (2011: US$20.4 million) in interest expense in respect of the Bonds and the Credit Facility, of which US$9.0 million (2011: US$9.8 million) was capitalised to intangible assets - exploration and appraisal expenditure.

12. Trade and other payables

The Group's accruals and deferred income at 31 March 2012 include US$13.0 million of prepayments from domestic customers in Kazakhstan for crude oil sales (2011: US$0.1 million).

The Group's other payables at 31 March 2011 include US$3.6 million of interest payable to the Kazakh tax authorities in relation to the Tax Claim, see note 7.

13. Share capital

The Company has two classes of share capital, which carry no right to fixed income: ordinary shares and deferred shares. Neither class of share is redeemable by the holder.

The holders of ordinary shares are entitled:

·; To receive notice of, attend and vote at any general meeting of the Company.

·; To receive dividends as may be declared from time to time and any distribution.

·; On a return of capital on a winding up, to receive payment of the nominal capital of 0.01p for each ordinary share held and a share in the Company's residual assets.

The deferred share class was created in 2005 in a capital restructuring and no further shares will be issued. A deferred share carries no voting or dividend rights. On a return of capital on a winding up, the holders of deferred shares shall only be entitled to receive the amount paid up on such shares after the holders of the ordinary shares have received the sum of 0.01p for each ordinary share held by them and shall have no other right to participate in the assets of the Company.

During the year ended 31 March 2012, the Company issued 100,355,247 ordinary shares, comprising:

·; The cashless exercise of 143,971,948 of the Credit Facility warrants, resulting in the issue of 94,793,580 new ordinary shares.

·; The exercise of 4,920,000 of the Bondholder warrants for total cash proceeds of US$0.4 million, resulting in the issue of 4,920,000 new ordinary shares.

·; The exercise of 641,667 share options for total cash proceeds of US$0.05 million, resulting in the issue of 641,667 new ordinary shares.

During the year ended 31 March 2011, the Company issued 481,682,114 ordinary shares, comprising: