MXP.L Regulatory News (MXP)

MAX PETROLEUM PLC

("MAX PETROLEUM", THE "COMPANY" AND TOGETHER WITH ITS SUBSIDIARIES, THE "GROUP")

[AIM: MXP]

2013 INTERIM RESULTS ANNOUNCEMENT

30 December 2013

Max Petroleum, an oil and gas exploration and production company focused on Kazakhstan, today announces its interim results for the six months ended 30 September 2013.

HIGHLIGHTS

Financial highlights:

· Revenue of US$46.3 million during the six months ended 30 September 2013, down 6% compared to US$49.2 million during the six months ended 30 September 2012. Revenue in excess of US$9.0 million per month subsequent to 30 September 2013.

· US$82.9 million borrowed under the senior credit facility with SB Sberbank JSC as of 30 September 2013, with the entire US$90 million facility drawn down as of the date of this announcement.

· Capital expenditure of approximately US$33 million during the six months ended 30 September 2013 with forecast total capital expenditure for the fiscal year ended 31 March 2014 of US$45-50 million, of which approximately US$39 million has been incurred to date.

· The Group is on target to drill 35 wells this fiscal year, with the average cost per well drilled since 31 March 2013 of US$0.9 million approximately 24% below originally budgeted costs.

· Several cost reduction initiatives have been implemented, which are beginning to be reflected in the Group's results, including:

· General and administrative costs excluding share-based payment down 14% from the comparable period, including a reduction in headcount of 12% from an average of 162 personnel during the six months ended 30 September 2012 to an average of 142 personnel in the current period;

· Introduction of water re-injection at Asanketken has reduced monthly water hauling charges from approximately US$300,000 in July 2013 to less than US$10,000 in November 2013; and

· Trucking Asanketken production to a nearby loading terminal since September 2013 has reduced aggregate oil trucking costs for all fields to approximately US$2.56 per barrel down from an average of US$4.27 per barrel during the six months ended 30 September 2013.

· Following receipt of the requisite regulatory approvals in August 2013, convertible bonds totalling US$28.6 million in principal and accrued interest were mandatorily converted into approximately 358 million ordinary shares at a price of 5p per share.

· Adjusted EBITDA was US$13.8 million for the six months ended 30 September 2013, down 23% compared to US$17.9 million for the six months ended 30 September 2012. Adjusted EBITDA has averaged in excess of US$3.5 million per month subsequent to 30 September 2013.

· Cash generated from operations was US$9.6 million during the six months ended 30 September 2013, down 69% compared to US$31.1 million during the six months ended 30 September 2012. Cash generated from operations is stated after various movements in working capital, as set out in Note 19 to the accompanying financial statements.

· Unrestricted cash of approximately US$11.6 million as of 28 December 2013.

Operational highlights:

· During the six months ended 30 September 2013, the Group drilled 19 post-salt wells, including 17 appraisal and development wells, of which 15 were successful, and two exploratory dry holes. Since 31 March 2013, the Group has drilled 31 post-salt wells, including 29 appraisal and development wells, of which 24 were successful, and two exploratory dry holes.

· Average daily production of 3,630 barrels of oil per day ("bopd") during the six months ended 30 September 2013, compared to 3,770 bopd during the six months ended 30 September 2012 and 3,346 bopd during the year ended 31 March 2013.

· Production for the fiscal year ended 31 March 2014 is now expected to average approximately 4,000 bopd, a revision downward from previous guidance of 4,500 to 5,500 bopd, due to regulatory delays in turning several wells onto test production and lack of forecast production from several unsuccessful wells drilled during the year to date. Daily production is currently approximately 4,500 bopd, including approximately 300 bopd from SAGW-9 and SAGW-12 that began test production in late December following the receipt of gas flaring permit approval from the Kazakhstan regulatory authorities.

· In May 2013, received final 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.

· 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 targeting unrisked mean resource potential of 467 million barrels of oil equivalent ("mmboe"). The Group is actively engaged in discussions with potential partners to finance the re-entry of NUR-1 during 2014.

Reserves and resources

The Group's competent person, Ryder Scott Company LLC ("RSC") has estimated the Group's reserves as at 30 September 2013 (the "CPR"), reflecting drilling results and other technical information as of that balance sheet date, including the updated infill 3D seismic acquisition over the Sagiz West field and partial results of the Group's ongoing 35 well drilling programme for the fiscal year ending 31 March 2014. The results are presented in the table below.

As at 30 September 2013, RSC estimated that the Group had 8.6 mmboe in proved and probable ("2P") reserves with an after-tax net present value discounted at 10% ("PV10") of US$140 million, a decrease of 21% from 10.9 mmbo in 2P as of 31 March 2013 with a PV10 of US$184 million. RSC estimated that the Group's total proved, probable and possible ("3P") reserves decreased by 32% to 9.7 mmboe as at 30 September 2013, with a PV10 of US$157 million, from total 3P reserves as of 31 March 2013 of 14.2 mmbo, with a PV10 of US$236 million.

Given the material drilling and testing results subsequent to 30 September 2013, especially with regards to the Sagiz West field that is now known to be a more complex and highly faulted/ compartmentalised structure than previously estimated, the CPR is not reflective of the Group's internal estimates of post-salt recoverable oil and gas volumes. The Group has drilled three successful appraisal wells in Sagiz West since 30 September 2013 that support the existence of a material hydrocarbon bearing fault block in the western central portion of the field. This fault block was excluded from the CPR prepared for these interim results because the wells were drilled after the balance sheet date. In order to provide shareholders with a more up to date estimate of reserves, RSC will prepare an updated reserve report for Sagiz West as of 31 December 2013, which is expected to be available in January 2014. As previously planned, the forthcoming reserve report for all of the Group's post-salt assets as of 31 March 2014 will also be prepared as soon as possible after 31 March 2014 (expected to be published no later than 31 May 2014).

Reserves as of 30 September 2013 are net of production during the period of 664,000 barrels.

The Group currently estimates Sagiz West's in-place resources to be 16 to 25 mmbo and 18 to 26 bcf of gas, which represent approximately seven to 10 mmboe of recoverable reserves. The Group expects that the remaining four wells in the Sagiz West appraisal drilling programme to be drilled in the next few months will substantially evaluate the potential size of the field as currently estimated by the Group.

The results of the Group's ongoing post-salt appraisal programme are more fully discussed in the Joint Chairmen's statement of this interim report.

Key Performance Indicators (KPIs)

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

1 Operating cost equals cost of sales less depreciation, depletion and amortisation (see note 6 to the accompanying financial information).

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 24 to the accompanying financial information.

Analyst and Investor Conference Call

There will be a conference call today to discuss this results announcement at 2pm London Time (2pm GMT). 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:

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.

JOINT CHAIRMEN'S STATEMENT

Dear Shareholder,

During the half year ended 30 September 2013, Max Petroleum completed the comprehensive debt restructuring it began in December 2012, extended the exploration period of its Blocks A&E Licence in Western Kazakhstan (the "Licence") until March 2015, and embarked on an extensive 35 well post-salt drilling programme for the year including two exploration wells and appraisal and development of several of its shallow discoveries. The Group was also able to progress its understanding and ability to re-enter and finish drilling the pre-salt NUR-1 well through completion of an extensive geomechanical and well design analysis with Halliburton that places the Group in a more capable position to bring in one or more financial or industry partners to evaluate its deep potential in Block E.

Production

The Group began the interim period with only the Zhana Makat field on production as it waited for final ratification of its Licence extension and incrementally increased its base line production as Asanketken was brought onto trial production ("TPP") in late May and Borkyldakty was put on full field development ("FFD") in July. These three fields were all on continuous production totalling approximately 4,000 bopd from August 2013, providing a strong platform of revenue and cash flow that has been augmented by more volatile test production from the Group's other shallow discoveries.

During the six months ended 30 September 2013, the Group produced 664,000 bbls, or 3,630 bopd, a decrease of 4% from total production of 690,000 bbls, or 3,770 bopd, in the prior period, but 24% higher than the 2,920 bopd produced during the six months ended 31 March 2013. The Group is currently producing approximately 4,500 bopd, including approximately 300 bopd from the SAGW-9 and SAGW-12 wells that began test production in late December following receipt of gas flaring permit approval from Kazakhstan regulatory authorities. Approximately 2,800 bopd of production is from fields on FFD, resulting in approximately 2,200 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 potential delays in regulatory approvals to begin testing wells, 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.

Based on current forecasts, the Group expects average production for the fiscal year ended 31 March 2014 to be approximately 4,000 bopd, a revision downward from the previous forecast of 4,500 to 5,500 bopd. This is principally due to non-productive appraisal wells drilled during the period, lack of production from the BCHW-2 well, and delays in obtaining regulatory approvals to place successful wells onto Test Production.

Post-salt Drilling Programme Update and Impact on Reserves

Max Petroleum drilled a total of 19 wells during the six month period, representing 54% of the shallow wells planned for this fiscal year. The drilling results have been mixed, with the Group drilling six successful development wells and nine successful appraisal wells during the interim period, as well as two non-productive appraisal wells and two exploratory dry holes. As of the date of this report, the Group has drilled 31 out of 35 post-salt wells, including six successful development wells, 18 successful appraisal wells, five non-productive appraisal wells, and two exploratory dry holes. The Group has gone from three rigs operating in September to one shallow rig operating today and has seen significant improvements in the time and cost to drill post-salt wells, with actual costs per well since 31 March 2013 of US$0.9 million averaging approximately 24% below original estimates. This reflects the practical application of experience drilling over 90 shallow wells to date, as well as the benefit of drilling multiple wells in succession without moving between different fields.

Key highlights of the drilling programme include five successful appraisal and development wells at Zhana Makat that have raised the productive capacity of the field to approximately 2,700 bopd. The appraisal wells at the Southeastern end of the Zhana Makat structure have performed particularly well, increasing the probability the field could extend further to the Southeast. Therefore, the Group is considering drilling an additional two appraisal wells in Zhana Makat during the first half of 2014.

Max Petroleum has also drilled six successful appraisal wells in the Sagiz West field in the current fiscal year, three of which were drilled after 30 September 2013. The wells at Sagiz West have shown that the majority of the central fault block running down the length of the field is productive. The Group is planning to drill another four appraisal wells in Sagiz West, which will allow it to prepare a comprehensive reserve evaluation and development plan for the field. A reduction in 2P reserves in Sagiz West as of 30 September 2013 is not reflective of the Group's expectations for ultimate field size (recoverable), which currently ranges between seven and 10 mmboe, including five to eight mmbo and 10 to 14 bcf of gas. Additional 3D seismic acquired over the Sagiz West field, along with drilling results to date, have shown the field to be a more complex and faulted/ compartmentalised structure than previously estimated, although the field is still expected to be commercially very valuable. Given the positive drilling results subsequent to 30 September 2013, the Group has engaged its competent person, Ryder Scott Company ("RSC"), to prepare an additional update of the Sagiz West field as of 31 December 2013 in order to provide a more current independent estimate of the field's potential value pending completion of the remaining appraisal programme over the next few months.

The Uytas drilling programme was less successful than expected, with two dry exploration wells drilled in the Uytas area and 10 out of 13 successful appraisal wells drilled through November 2013 that together appear to limit the productive area to the eastern section of the field and did not reflect a broad presence of non-conventional oil saturation in the shallow Albian section across the structure. A total of 18 wells have now been drilled in Uytas to date and appraisal drilling is complete. The Group's revised estimate of overall oil in place ("OOIP") for the field is approximately 28 mmbo, with ultimate recoverable reserves and value dependent on how efficiently the field can be developed and operated from a cost perspective and the average production rates per well from the shallow Cretaceous and Jurassic sands that are high quality but do not have much reservoir energy. Testing of the new appraisal wells in the field is ongoing, with rates ranging from a few barrels in marginal wells up to 37 bbls per day, with wells in the main producing area averaging approximately 20 bopd. Future development plans currently envisage drilling 26 additional development wells in the field, with average well costs of US$300-500,000 per well, after Uytas moves into TPP in early 2015. Given that much of the appraisal drilling and all of the related testing of these wells occurred after 30 September 2013, a more comprehensive update of the field will be included in the Group's CPR as of 31 March 2014 although an average production rate of 20 bopd was reflected in the reserve estimates for the CPR as of 30 September 2013.

A two well appraisal programme at Baichonas West yielded one Jurassic gas well with a large oil column in the Triassic section that has not proven to be productive, followed by a dry hole. This has led to a significant downgrade in the reserves assigned by RSC to the Baichonas West field, although the Group believes there could be additional upside in the field. The Group is considering one additional well in the field during the latter half of fiscal year 2015.

At Eskene North, the Group successfully drilled the ESKN-2 appraisal well in October 2013 confirming the presence of a large hydrocarbon bearing structure the Group estimates to contain OOIP of approximately 21 mmbo. The Triassic reservoirs have low permeability, but are fairly porous and oil-filled, which makes them good candidates for hydraulic fracture stimulation that may increase productivity up to five fold. The Group initiated fracture stimulation of the ESKN-1 well in late December 2013, successfully injecting the "frac" fluids into the target reservoirs and the Group has recovered oil in the initial clean-up of the well. The Group expects to have an update on this well over the next several weeks and will evaluate when and how to proceed with a planned hydraulic fracturing stimulation treatment of the ESKN-2 well, depending upon the results and whether to drill any additional appraisal wells in the field prior to moving to TPP in 2015. Presently, all of the OOIP in the field is classified as resources pending demonstration of the viability of hydraulic fracture stimulation before reserve estimates and economics can be properly determined. If the field is determined to be commercially viable, it will be included in the Group's reserve report for the year ended 31 March 2014.

In the East Kyzylzhar I field, a high quality 3D seismic survey acquired earlier this year has shown remaining potential in the field for up to three additional high-rate wells targeting sandstone "channel" reservoirs in structurally high areas. Additional technical work to allow direct mapping of these reservoirs is still being finalised and additional appraisal wells will be considered for drilling in fiscal year 2015.

Shallow Exploration Potential

The Group has identified two shallow exploration prospects and three leads located in the Northern area of Block E with unrisked resource potential ranging between five and 11 mmbo each. The prospects include Jurassic and Triassic prospects in the Tolegen West area and three promising Cretaceous, Jurassic and Triassic leads in the Dossor Southwest area between the Dossor and Sagiz West fields. The Group is progressing with regulatory approval in order to potentially drill up to three additional exploration wells during fiscal year 2015, which it expects would generate at least one additional shallow discovery based on the Group's historical track record in shallow exploration.

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 both to 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 to reach target depth and the feasibility of re-entry. The first step was to conduct 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 signed a memorandum of understanding with Halliburton during the six months ended 30 September 2013, 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. The Group is currently engaged in active discussions to finance the re-entry of the NUR-1 well during 2014. Finishing the well and evaluating this high potential target remains a top priority for the Group.

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 US$90 million 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. 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 begin continuous production and as they move from TPP to FFD, 80% of the production is available to sell on export markets for a substantially higher price per barrel. The Group is currently producing approximately 4,500 bopd generating in excess of US$9 million per month in revenue and significant net cash flow from operations. The Group had approximately US$11.6 million in cash on hand as of 28 December 2013.

The Group is working diligently to enhance its liquidity position through the reduction of operational and administrative costs across the organisation. Over the last fiscal year, the Group has implemented a reduction in headcount of approximately 12% from an average of 162 personnel to 142 in the current period. Besides the 24% reduction of drilling costs compared to budget discussed above, the Group is making meaningful improvements in its field level production and transportation costs, including in excess of US$7 per bbl savings in trucking and water disposal costs in Asanketken over the last several months and an expected US$4 per bbl savings in Zhana Makat when the Group commissions the new Makat oil terminal that will allow the Group direct access into the pipeline bypassing a third-party provider. The combination of these initiatives will have a positive impact on the current fiscal year's results and a significant impact on the fiscal year ending in March 2015 and beyond, as the Group continues to seek ways to streamline its operations as it continues to evolve into a more efficient production company.

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$54 million was utilised to repay Macquarie and certain tendering Bondholders. As of the date of this report, the Group had fully drawn the Sberbank Facility, spending approximately US$36 million in capital expenditures relating to the Group's post-salt programme. The Sberbank Facility matures in November 2017 with quarterly amortisation payments beginning in March 2014.

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$20-25 million in additional capital to finish drilling the NUR-1 well, which will not be funded out of the Group's existing capital resources. The Group is currently looking for financial or industry partners 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 US$45-50 million in capital expenditure for the fiscal year ended 31 March 2014, of which approximately US$39 million had already been incurred as of 30 November 2013. The Group intends to fund its post-salt capital programme beyond 31 March 2014 using cash flow from operations. However it has the flexibility to expand activities depending on available capital and the Group is currently investigating accelerating its post-salt programme by obtaining additional borrowing capacity under the Sberbank facility through a revolving working capital arrangement, by deferral of some or all of the 2014 principal amortisation payments into future periods, or a combination of both.

Over the last year, Max Petroleum has taken the important and necessary steps to restructure its balance sheet and strengthen its capabilities as a production company to create a platform for sustained growth in production, cash flow and EBITDA going forward. The Group will continue to appraise and develop its post-salt assets, while pursuing meaningful exploration opportunities in the post-salt and doing everything it can to unlock the potentially very high returns from its pre-salt assets. All of these activities are drivers of value for the Group in the future. On behalf of the Board, management and employees of Max Petroleum, we want to thank our shareholders for their continued support as we seek to create meaningful value out of our assets in the upcoming year ahead.

James A. Jeffs Robert B. Holland

Executive Co-Chairman Executive Co-Chairman

Independent Review Report to Max Petroleum Plc

Introduction

We have been engaged by the Company to review the condensed consolidated interim financial information in the interim financial report for the six months ended 30 September 2013, which comprises the Condensed Consolidated Income Statement, Condensed Consolidated Statement of Comprehensive Income, Condensed Consolidated Balance Sheet, Condensed Consolidated Statement of Changes in Equity, Condensed Consolidated Cash Flow Statement and related notes. We have read the other information contained in the interim financial report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the condensed consolidated interim financial information.

Directors' responsibilities

The interim financial report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the interim financial report in accordance with the AIM Rules for Companies which require that the financial information must be presented and prepared in a form consistent with that which will be adopted in the Company's annual financial statements.

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

Our responsibility

Our responsibility is to express to the Company a conclusion on the condensed set of financial statements in the interim financial report based on our review. This report, including the conclusion, has been prepared for and only for the Company for the purpose of the AIM Rules for Companies and for no other purpose. We do not, in producing this report, accept or assume responsibility for any other purpose or to any other person to whom this report is shown or into whose hands it may come save where expressly agreed by our prior consent in writing.

Scope of review

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

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the condensed consolidated interim financial information in the interim financial report for the six months ended 30 September 2013 is not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the AIM Rules for Companies.

PricewaterhouseCoopers LLPChartered Accountants29 December 2013London

Notes:

The maintenance and integrity of the Group's website is the responsibility of the directors; the work carried out by the auditors does not involve consideration of these matters and, accordingly, the auditors accept no responsibility for any changes that may have occurred to the financial statements since they were initially presented on the website.

Legislation in the United Kingdom governing the preparation and dissemination of financial statements may differ from legislation in other jurisdictions.

MAX PETROLEUM PLC

CONDENSED CONSOLIDATED INCOME STATEMENT

For the six months ended 30 September 2013

(in thousands of US$)

The notes form an integral part of this condensed consolidated financial information.

MAX PETROLEUM PLC

CONDENSED CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the six months ended 30 September 2013

(in thousands of US$)

The notes form an integral part of this condensed consolidated financial information.

MAX PETROLEUM PLC

CONDENSED CONSOLIDATED BALANCE SHEET

At 30 September 2013

(in thousands of US$)

The notes form an integral part of this condensed consolidated financial information.

MAX PETROLEUM PLC

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the six months ended 30 September 2013

(in thousands of US$)

The notes form an integral part of this condensed consolidated financial information.

MAX PETROLEUM PLC

CONDENSED CONSOLIDATED CASH FLOW STATEMENT

For the six months ended 30 September 2013

(in thousands of US$)

The notes form an integral part of this condensed consolidated financial information.

NOTES TO CONDENSED CONSOLIDATED FINANCIAL INFORMATION

For the six months ended 30 September 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.

Max Petroleum 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.

The interim financial report for the six months ended 30 September 2013 was approved by the Board of Directors on 29 December 2013.

2. Basis of preparation and accounting policies

The annual financial statements of Max Petroleum are prepared in accordance with International Financial Reporting Standards as adopted by the European Union. The unaudited condensed consolidated financial information for the six months ended 30 September 2013 included in this interim financial report (the "interim financial report") has been prepared in accordance with International Accounting Standard 34 "Interim Financial Reporting", as adopted by the European Union.

The interim financial report does not include all the information and disclosures required in the annual financial statements, and should be read in conjunction with the consolidated financial statements in the Max Petroleum Annual Report and Accounts for the year ended 31 March 2013. The accounting policies adopted in the preparation of the interim financial report, the significant judgements made by management in applying the Group's accounting policies, and the key sources of estimation uncertainty are consistent with those followed in the preparation of the Group's financial statements for the year ended 31 March 2013, except for the adoption of the following standards and amendments:

The adoption of the above new and revised standards has had no effect on the reported financial results or the disclosures in this interim financial report.

The Group's interim financial report does not comprise statutory accounts within the meaning of Section 434 of the Companies Act 2006. Statutory accounts for the year ended 31 March 2013 were approved by the Board of Directors on 21 August 2013 and delivered to the Registrar of Companies. The report of the auditors on those accounts was unqualified and did not contain a statement under Section 498(2) or (3) of the Companies Act 2006.

Principal risks and uncertainties

The Group is subject to various risks relating to political, economic, legal, social, industry, business and financial conditions. The Directors do not consider that the principal risks and uncertainties of the Group have changed since the publication of the Annual Report and Accounts for the year ended 31 March 2013. The principal risks and uncertainties are detailed on pages 29 to 31 of the 2013 Annual Report and Accounts. The principal risks and uncertainties are more fully disclosed in note 26 of this interim financial report.

In addition, the Group's activities expose it to a variety of financial risks: market risk, credit risk and liquidity risk. The interim financial report does not include all financial risk management information and disclosures required in the annual financial statements; they should be read in conjunction with the Group's Annual Report and Accounts for the year ended 31 March 2013 and there have been no changes in these risks or in any risk management policies.

Going concern

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 US$90 million 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. 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 is available to sell on export markets for a substantially higher price per bbl. The Group is currently producing approximately 4,500 bopd generating in excess of US$9 million per month in revenue and significant net cash flow from operations. The Group had approximately US$11.6 million in cash on hand as of 28 December 2013.

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$54 million was utilised to repay Macquarie and certain tendering Bondholders. As of the date of this report, the Group had fully drawn the Sberbank Facility, spending approximately US$36 million in capital expenditures relating to the Group's post-salt programme. The Sberbank Facility matures in November 2017 with quarterly amortisation payments beginning in March 2014.

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$20-25 million in additional capital to finish drilling the NUR-1 well, which will not be funded out of 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 US$45-50 million in capital expenditure for the fiscal year ended 31 March 2014, of which approximately US$39 million had already been incurred as of 30 November 2013. The Group intends to fund its post-salt capital programme beyond 31 March 2014 using cash flow from operations. However it has the flexibility to expand activities depending on available capital and the Group is currently investigating accelerating its post-salt programme by obtaining additional borrowing capacity under the Sberbank facility through a revolving working capital arrangement, by deferral of some or all of the 2014 principal amortisation payments into future periods, or a combination of both.

The Group was in technical breach of certain banking covenants related to production and reserves at 30 September 2013. Accordingly, the entire loan facility has been classified within current liabilities in the Group balance sheet. The Group expects to reset the covenants in line with the Group's forecasts prior to 31 March 2014.

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 these interim financial statements.

3. Loss per share

The calculation of basic and diluted earnings per share is based on the following data:

The Company's potentially dilutive securities, being the outstanding share options and warrants in issue, were anti-dilutive for the six month periods ended 30 September 2013 and 2012, respectively.

4. Dividends paid and proposed

No dividend was paid or is proposed for the six month periods ended 30 September 2013 and 2012, respectively.

5. 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.

The Group's production and sale of hydrocarbons is not materially affected by seasonal factors or fluctuations.

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.

6. Cost of sales

7. Operating profit

The following items of an unusual or significant nature have been charged to operating profit during the interim period:

Exploration and appraisal costs relate mainly to the cost of dry holes, including costs for plugging and abandonment. During the six months ended 30 September 2012, exploration and appraisal costs included a loss of US$0.4 million which arose on the disposal of inventories of drilling supplies and a charge of US$0.5 million to reduce the carrying amount of remaining inventories to their net realisable value.

8. Finance costs

9. Income taxes

The Group's principal business activities are in the Republic of Kazakhstan, where corporate income tax applies at a rate of 20% of taxable income. Mineral extraction tax, export rent tax and export customs duty are taxes relating to the production and sale of hydrocarbons and are accounted for as cost of sales (see note 6).

Where the realisation of deferred tax assets is dependent on future profits, the Group recognises losses carried forward and other deferred tax assets only to the extent that the realisation of the related tax benefit through future taxable profits is probable.

The movements in the Group's deferred tax assets and liabilities are as follows:

10. Capital expenditure

The US$182.4 million carrying value of the intangible exploration and appraisal asset at 30 September 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 and Gas of the Republic of Kazakhstan (the "MOG"). 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$41.0 million directly relating to the NUR-1 pre-salt well (31 March 2013: US$40.7 million). If the Group was unsuccessful in drilling the NUR-1 well, it would have to reassess the carrying value of the whole of the intangible exploration and appraisal asset.

In assessing whether there were any indicators of impairment for oil and gas producing assets and associated property, plant and equipment, 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 30 September 2013 and management estimates. The results of the comparison indicate that the expected recoverable amount of each field exceeds its net book value.

11. Trade and other receivables

Trade and other receivables include US$11.3 million of Kazakh VAT (31 March 2013: US$8.3 million), of which US$7.9 million is expected to be recovered after more than one year (31 March 2013: US$5.9 million).

12. Restricted cash

Restricted cash comprises US$2.8 million required to be deposited in an environmental restoration and rehabilitation fund under the terms of the Group's Blocks A&E Licence (31 March 2013: US$2.8 million).

13. Trade and other payables

Trade and other payables include US$14.7 million of prepayments from customers for crude oil sales (31 March 2013: US$19.2 million).

14. Borrowings

Bank borrowings

In December 2012, the Group closed a US$90 million credit facility (the "Sberbank Facility") with SB Sberbank JSC ("Sberbank") to refinance the previous credit facility with Macquarie Bank Limited (the "Macquarie Facility" and "Macquarie"), fund the cash portion of a tender offer made to convertible bondholders, and fund capital expenditures on the Group's post-salt exploration, appraisal and development programme.

 The material provisions of the Sberbank Facility are as follows:

- Interest rate of 11% per annum, payable monthly.

- Five-year term maturing in November 2017, with quarterly amortisation payments beginning in March 2014.

- Secured by pledges in favour of Sberbank over the Group's assets in Kazakhstan.

- Available for drawdown through 31 December 2013.

A reconciliation of the amounts outstanding under the Group's bank borrowings is as follows:

At 30 September 2013, US$7.1 million remained available for drawdown under the Sberbank Facility. As the Group was in technical breach of certain banking covenants related to production and reserves at that date the entire loan facility has been classified within current liabilities in the Group balance sheet. The Group expects to reset the covenants in line with its forecasts prior to 31 March 2014.

PIK notes

In December 2012, as part of a comprehensive restructuring of its outstanding debt facilities, the Group's convertible bondholders agreed to exchange the outstanding bond principal and accrued interest of US$90.2 million for 709 million ordinary shares, PIK notes with a principal of US$26.7 million and promissory notes with a principal of US$3.4 million. For further details of the restructuring please refer to the Group's Annual Report and Accounts for the year ended 31 March 2013.

The PIK note principal of US$26.7 million, plus interest accruing at a rate of 10% per annum, was subject to mandatory conversion into ordinary shares upon receipt of approval under Article 12 of the Kazakhstan Law on Subsoil and Subsoil Use, at a conversion price of 5 pence per ordinary share with a fixed exchange rate of US$1.6 per £1. Following written receipt of the approval, the outstanding principal and accrued interest of US$28.6 million was converted into 357,571,134 ordinary shares (note 16).

Movements in the carrying value of the PIK notes during the period are analysed as follows:

The conversion of the PIK notes, and the earlier conversion of convertible bonds into 709 million shares announced on 21 December 2012, triggered certain anti-dilution provisions of warrants held by syndicate partners in the Company's former credit facility with Macquarie (the "Syndicate Warrants"). As a result, holders of the Syndicate Warrants were granted additional warrants granting them a right to subscribe for approximately 49 million ordinary shares at 5p per Share.

15. Provisions for liabilities and other charges

16. Share capital

In August 2013, the Company received written regulatory approval from the Ministry of Oil and Gas of the Republic of Kazakhstan permitting the conversion of the Company's outstanding PIK notes (note 14), comprising US$28.6million in principal and accrued interest, into ordinary shares of the Company. The PIK notes were mandatorily converted into 357,571,134 shares at a price of 5 pence per share.

At 30 September 2013, the Company had in issue 2,175,305,483 allotted and fully paid ordinary shares of 0.01 pence each (31 March 2013: 1,817,734,349 ordinary shares).

During the six months ended 30 September 2012, the Company issued 8,035,708 ordinary shares at 5 pence per share to Zhanros Drilling LLP ("Zhanros"). The shares were issued in settlement of US$0.6 million of drilling services received from Zhanros, in accordance with the Zhanros Agreement (see note 17).

At 30 September 2012, the Company had in issue 1,026,524,566 allotted and fully paid ordinary shares of 0.01 pence each (31 March 2012: 1,018,488,858 ordinary shares).

17. Other reserves

On 8 August 2012, Max Petroleum Plc entered into an agreement with Zhanros, one of its drilling contractors, whereby Zhanros agreed to fund up to US$7.0 million of drilling and workover services in exchange for ordinary shares in the Company (the "Zhanros Agreement"). Under the terms of the Zhanros Agreement, Zhanros agreed to drill up to four shallow, post-salt wells and fund related ancillary services in exchange for up to 90,322,581 ordinary shares in the Company at a price of 5 pence per share in lieu of cash payment.

During the 6 months ended 30 September 2012, the Group received US$3.3 million of services under the Zhanros Agreement, of which US$0.6 million were settled by the issue of shares prior to 30 September 2012 (note 16).

18. Share-based payment

Full details of the Group's share option schemes are outlined on pages 86 to 88 of the Group's Annual Report and Accounts for the year ended 31 March 2013.

During the six months ended 30 September 2013, Max Petroleum granted 3,000,000 options to officers and employees of the Group with an exercise price of 5p and term of 4 years. 7,500 options were forfeited by leavers, 4,861,501 expired and none were exercised. The total number of options outstanding at 30 September 2013 was 208,436,176. The Group recorded a share-based payment charge of US$1.6 million for the six months ended 30 September 2013.

During the six months ended 30 September 2012, Max Petroleum granted 1,200,000 options to officers and employees of the Group with exercise prices ranging from 5p to 11.75pper share and with a term of seven years. 1,314,250 options were forfeited by leavers, 263,568 expired and none were exercised. The total number of options outstanding at 30 September 2012 was 109,360,245. The Group recorded a share-based payment charge of US$1.2 million for the six months ended 30 September 2012.

19. Notes to the cash flow statement

Cash generated from operations

Summary of non-cash items

1 Including drilling and ancillary services under the Zhanros Agreement (note 17).

20. Financial instruments' fair value disclosures

Except as detailed in the following table, the directors consider that the carrying value amounts of financial assets and financial liabilities recorded at amortised cost in the financial statements are approximately equal to their fair values:

The fair value of bank borrowings approximates to their gross carrying value. The fair value of the PIK notes at 31 March 2013 was determined by reference to the published closing price quotation from the Channel Islands Stock Exchange on that date.

21. Related party transactions

Transactions between the Group and its subsidiaries, which are related parties, have been eliminated on consolidation and therefore are not disclosed in this note.

22. Commitments and contingencies

The Group is committed under its Licence to certain future expenditures including a minimum work programme and reimbursement of historical costs incurred by the Government of the Republic of Kazakhstan. The Group's commitments under its Licence are as follows:

The minimum work programme is agreed with the MOG and covers exploration and production activities in Blocks A&E from 2013 to 2021. It also includes social infrastructure contributions and commitments for the training of local personnel. Qualifying exploration, development and operating expenditure incurred by the licence holder are deductible from these future commitments. During the six months ended 30 September 2013, the Group and the MOG signed amendments to the Blocks A&E Licence which extended the exploration period to March 2015 and transferred the Borkyldakty field to FFD. The amendments increased the minimum work programme, including obligations for the Group's planned appraisal and development of its post-salt discoveries.

The total commitment at 30 September 2013 includes US$24.2million of historical costs incurred by the Republic of Kazakhstan for the exploration of Blocks A&E prior to the Group's acquisition of the Licence (31 March 2013: US$24.2 million). Historical costs become payable from the date when a certain field is transferred to the production stage under FFD and the amount payable for the field is determined by the Government of the Republic of Kazakhstan in a separate agreement. The amount of historical costs allocated to each discovery is determined based on a mining allotment agreed with the Government of the Republic of Kazakhstan once a commercial discovery has been made and FFD has started.

Transfer Pricing Claims

The Kazakhstan tax authorities have carried out transfer pricing tax audits of Max Petroleum Plc's subsidiary Samek International LLP for the tax years ended 31 December 2007 and 31 December 2008. Although the Group's oil sales were made on an arms-length basis with unrelated third parties, the tax authorities have challenged the differential between the actual selling price the Group received and market prices at the time. This differential arises principally due to transportation costs which are paid for by the buyer, but suffered by the Group when the selling price is agreed.

Following the tax audits, the Group received notifications (the "Transfer Pricing Claims") requesting the payment of US$0.7 million and US$1.5 million for the 2007 and 2008 tax years, respectively. The Transfer Pricing Claims include corporate income tax, mineral extraction tax, penalties and interest.

The Group believes that the transportation costs deducted by the buyers are valid and within reasonable norms and that the Transfer Pricing Claims are without merit. Therefore no payment has been made towards the Transfer Pricing Claims and no provision has been made in these financial statements for these contingent liabilities. The Group is in the process of appealing the Transfer Pricing Claims with the relevant tax authorities and through the courts.

23. Post balance sheet events

Sberbank Facility

Subsequent to 30 September 2013, the Group borrowed a further US$7.1 million under the Sberbank Facility (note 14), resulting in a total balance of US$90.0 million at the date of this report.

Amendment to the Blocks A&E Licence

In November 2013, The Group and the MOG signed an amendment to the Licence which increased the minimum work programme. Accordingly, the Group's commitments under its subsoil contract increased from US$127.0 million (note 22) to US$137.4 million.

24. Non-IFRS measures

The Group presents Earnings Before Interest, Tax, Depreciation and Amortisation ("Adjusted EBITDA") as a non-IFRS earnings measure to provide additional information to investors in order to allow an alternative method for assessing the Group's financial results. Adjusted EBITDA is defined as operating profit/(loss) before depreciation, depletion and amortisation, share-based payment expense and exploration and appraisal costs and impairment losses. Adjusted EBITDA is a key performance indicator used by the Board to measure underlying operating profitability.

A reconciliation of operating profit to Adjusted EBITDA is shown below:

25. Publication of the interim financial report

Copies of the interim financial report are available on the Company's website, www.maxpetroleum.com.

26. 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 its ability to recover any losses it may incur during that period and on its ability to maintain adequate reserves.

As the Group does not currently hedge its crude oil production it is exposed to the risk of oil price movements. As more fields enter FFD and daily production sold into the export market increases, management may reassess whether it should enter into price hedging contracts in order to achieve more predictable cash flows from its future crude oil production.

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.

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 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 period.

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 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 of the Republic of Kazakhstan.

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 12 months from the date of signing of these financial statements which indicate that it has sufficient liquidity and capital resources in order to continue to operate as a going concern, including funding its post-salt appraisal and development programme, administrative and operating expenses, and servicing the interest and amortisation payments due under the Sberbank Facility. The Group is also seeking additional working capital to expand and/or accelerate its shallow drilling programme during 2014 as well as to farm-out its pre-salt assets to fund the re-entry of the NUR-1 well on Block E.

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 Joint Chairmen's Statement.