Max Petroleum : 2014 Annual Report and Accounts and Notice of AGM

MAX PETROLEUM PLC

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

WITH ITS SUBSIDIARIES, THE "GROUP")

[AIM: MXP]

2014 ANNUAL REPORT AND ACCOUNTS AND NOTICE OF AGM

20 August 2014

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 2014. The Company also announces that its Annual General Meeting will be held at 11:00 am on Tuesday 30 September 2014, at the Lansdowne Club, 9 Fitzmaurice Place, Mayfair, London W1J 5JD. A copy of the Company's annual report will be available on the Company's website at www.maxpetroleum.com and will be posted to shareholders with the notice convening the Annual General Meeting providing details of the venue, on or before 29 August 2014.

1. Adjusted EBITDA is defined as profit/(loss) before finance income, finance expense, income tax expense, depreciation, depletion and amortisation, share-based payment expense, exploration and appraisal costs, restructuring 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 23 to the accompanying financial information.

2. Reserves estimated by the Ryder Scott Company, the Group's competent person, as at 31 March 2014 and 31 March 2013, respectively.

·       Revenue of US$100.4 million during the year ended 31 March 2014, up 8% compared to US$93.3 million during the year ended 31 March 2013.

·       Average daily production of 3,899 bopd, up 17% on the previous year.

·       Drilled 35 post-salt wells during the year ended 31 March 2014, taking the total to 103 wells drilled between August 2006 and August 2014.

·       2P reserves of 9.5 mmboe at 31 March 2014, down 13% from 10.9 mmboe at 31 March 2013, up 11% from 8.6 mmboe at 30 September 2013.

·       Impaired the book value attributed to post-salt exploration assets by US$64.6 million, reflecting the limited remaining post-salt exploration potential of the Blocks A&E Licence.

·       Commenced a cost-cutting initiative that is expected to generate recurring annual savings of approximately US$4.0 million in administrative costs. Provision for one-off restructuring costs of US$3.8 million recognised at 31 March 2014.

·       Commissioned a new oil pipeline and associated terminal facility in June 2014 that will result in a reduction of transport costs of approximately US$4.0 per barrel for production from the Zhana Makat, Borkyldakty, Sagiz West and East Kyzylzhar I fields.

·     T he Asanketken field is expected to be granted full field development status by the end of 2014.

·       Current production of approximately 3,400 bopd from fields in continuous production (Zhana Makat, Borkyldakty and Asanketken), generating over US$8.0 million revenue per month.

·       Production for the four months ended 31 July 2014 averaged approximately 4,250 bopd, including test production from several appraisal wells at Sagiz West and East Kyzylzhar I, which are currently, or will soon be, shut-in pending commencement of trial production ("TPP").

·       The Sagiz West, East Kyzylzhar I and Baichunas West fields on track to gain TPP status in 2015 allowing for continuous production from all wells at those fields which is expected to bring on stream in excess of 1,000 bopd of additional production.

·       NUR-1 re-entry plan designed by Halliburton and submitted to CaspiyMunaiGas LLP, a design institute, for approval.

·       Began quarterly repayments of the Sberbank loan principal in March 2014, with a total of US$4.1 million repaid as of 19 August 2014.

·      Completed conversion of the remaining outstanding convertible bonds into ordinary shares in September 2013, the final part of the restructuring of the Group's debt facilities first announced in December 2012.

·       In August 2014, agreed a conditional strategic investment by AGR Energy in Max Petroleum of approximately US$62.5 million before expenses, which would result in AGR Energy holding 51% of the Company's share capital on completion. 

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

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

2. Adjusted EBITDA is defined as profit/(loss) before finance income, finance expense, income tax expense, depreciation, depletion and amortisation, share-based payment expense, exploration and appraisal costs, restructuring 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 23 to the accompanying financial information.

3. Reserves estimated by Ryder Scott, the Group's competent person as at 31 March 2014, 31 March 2013 and 31 March 2012, respectively.

James A Jeffs, Executive Chairman, wrote in the Chairman's Statement in this year's 2014 Annual Report and Accounts:

"Max Petroleum has taken important steps this year to shift its focus from exploration to production. The changes have followed disappointing progress in adding to reserves from the post-salt, slower than expected production growth and limited advancement towards resuming drilling of the deep, pre-salt NUR-1 well. The increased emphasis on production and cost reduction follows reduced exploration activity in the post-salt after a busy period of appraisal drilling in 2013, which was followed by a reduced estimate of Group reserves from our competent person, Ryder Scott Company, and a non-cash impairment of the post-salt exploration asset by US$64.6 million. The disappointing operational news in the form of slower than expected production growth has made change more urgent, but improved efficiency was also a necessary and logical step given the stage of development of the Group and its assets. The structural changes to the management and operations of the Group which were made earlier in 2014 are now complete and are the start of an ongoing drive for improved efficiency.

In July 2014, the Group announced the commencement of a strategic review and formal sale process with the intention of maximising value for shareholders. In early August 2014, Max Petroleum announced a proposed US$62.5 million equity infusion by AGR Energy Limited No. I ("AGR Energy"), a vehicle owned by the Assaubayev Group ("AB").  In exchange, AGR Energy would receive a 51% equity interest in Max Petroleum, which the Board understands from AB would remain a publicly traded UK company focused on Kazakhstan.

I believe Max Petroleum offers an excellent platform to consolidate and grow oil and gas opportunities in Kazakhstan and, together with the Board of Directors, I see the prospect of a partnership with AB as highly positive for Max Petroleum's shareholders and consider that the proposed transaction would substantially strengthen the Group's balance sheet. It is anticipated that my colleague and fellow director, Robert Holland, Max Petroleum's Interim Chief Executive Officer, and I would continue as members of the Board if this transaction is consummated. The transaction is subject to a number of conditions, including shareholder approval, Kazakhstan regulatory approvals and an acceptable revision of Max Petroleum's credit relationship with Sberbank.

If this transaction is completed, the investment by AB should enable the Group to fund its planned capital programme to develop its post-salt fields and maximise reserves and production. In addition, Max Petroleum would be in a strengthened position to attract financial or industry partners to help finish its pre-salt NUR-1 well and to secure an extension of the exploration period of its Blocks A&E Licence in western Kazakhstan to enable it to have time to finish drilling NUR-1 and, if it is successful, the Kurzhem well. The Group would also be able to consider investment in other projects in Kazakhstan and across Central Asia that complement its existing activities.

I appreciate the difficulties experienced by Max Petroleum's shareholders, who have seen during the last year a series of disappointments in terms of reserves, slower production growth and our delayed pre-salt exploration plans leading to a correspondingly very disappointing share price performance. I believe that the proposed AB transaction would position Max Petroleum to capture the value inherent in developing our post-salt assets while preserving the valuable optionality in the pre-salt. I see significant value in the Max Petroleum operating platform and believe a recapitalised Max Petroleum offers considerable upside for its shareholders and employees.  Further details of the rationale for the investment by AGR Energy will be set out in a circular to be distributed to all shareholders in due course."

Enquiries:

Kenneth Hopkins, Chief Operating Officer of Max Petroleum Plc, is the qualified person that has reviewed and approved the technical information contained in this announcement. Mr Hopkins holds a Bachelor of Science degree in Marine Sciences and a Master of Science degree in Geology from Texas A&M University and is a certified petroleum geologist with 32 years of experience in the oil and gas industry.

Reserve estimates have been compiled in accordance with the 2011 Petroleum Resources

During 2014 the Group made significant changes to its management structure and operating approach in order to maximise efficiency and ensure the execution of its operational plans using its available financial resources. These changes followed a planned reduction in the scale of the Group's exploration and appraisal activities after a year in which it drilled a record 35 wells. The changes were also a response to disappointing reserves as assessed by the Group's competent person, Ryder Scott Company ("Ryder Scott"), as of 30 September 2013, slower than expected increases in production, and a lack of significant progress towards resumption of drilling the deep, pre-salt NUR-1 well.

The underlying strengths of the Group's business, including its employees, the Blocks A&E Licence and a reputation as a respected and effective operator in Kazakhstan remain major assets. Greater efficiency and an increased focus on production during 2014 have already begun to have a positive impact. The cost-cutting initiative that commenced in early 2014 will reduce annual administrative costs by approximately US$4 million. This initiative includes the closure of the Group's Houston office and streamlining of management across the Group's operations.

Max Petroleum increased annual revenue over the previous year by 8% to over US$100 million with production up for the fourth consecutive year to an average of 3,899 bopd during the year ended 31 March 2014. Adjusted EBITDA increased by 9% from US$31.5 million to US$34.5 million and selling and transportation costs per barrel fell by 7% from US$11.55 per bbl to US$10.78 per bbl. The Group is currently producing approximately 3,400 bopd from fields on continuous production (Zhana Makat, Borkyldakty and Asanketken) and generating over US$8 million per month in revenue. The Group expects its total production to average around this level from now until Sagiz West is approved for trial production ("TPP") and commences continuous production, expected in Q2 2015.

In March 2014, the Group began to pay down the US$90 million loan principal borrowed under the credit facility with Sberbank (the "Sberbank Loan"). Principal repayments were approximately US$2 million in March and June 2014 so that by 19 August 2014 the total owing under the Sberbank Loan was approximately US$86 million. Further repayments of approximately US$3.1 million each are scheduled for September and December 2014, followed by a repayment of US$6.7 million in March 2015 and then US$6.6 million per quarter until maturity in November 2017.

During the year the Group drilled 35 wells, including 11 wells at Sagiz West and 14 lower cost shallower wells at the Uytas field. In April and May 2014, the Group also drilled two successful wells and one dry hole at the East Kyzylzhar I field. This extensive drilling programme enabled substantial appraisal of these three fields as well as other parts of the portfolio. As a result, the Group's understanding of Sagiz West, Uytas and East Kyzylzhar I has been significantly advanced, with sufficient detailed data gathered for the process of applying for TPP to proceed. It is expected that all three fields will gain TPP status in 2015 and from that point continuous production will be permitted from all the wells at each of these fields.

During the past financial year the Group was also able to transfer the Asanketken field to TPP in May 2013 and the Borkyldakty field to Full Field Development ("FFD") in July 2013. Later in 2014 it is expected that the Asanketken field will proceed to FFD and as a result 80% of its production will be eligible for export.

Total remaining 2P reserves estimated by Ryder Scott decreased by 13% from 10.9 mmboe as of 31 March 2013 to 9.5 mmboe as of 31 March 2014. The reserves as of 31 March 2014 were, however, up 11% from 8.6 mmboe as of 30 September 2013. Total oil production for the year ended 31 March 2014 was a record 1.4 mmbo, up 17% from 1.2 mmbo in the prior year.

To reflect the reality of 2P reserves of 9.5 mmboe as of 31 March 2014, which are significantly lower than prior expectations, and the limited remaining exploration potential of the post-salt assets, a non-cash impairment charge of US$64.6 million has been taken against the historic non-drilling exploration costs allocated to these assets. This reflects a conservative view that given the uncertainty over the availability of funding for the additional investment necessary to fully develop the Group's post-salt fields, it is no longer appropriate to carry forward the US$64.6 million exploration asset allocated to the post-salt fields in the Group's balance sheet.

The ability of the Group to develop its post-salt assets and effectively market its oil production continues to be a valuable asset and there remains an intention and capability to re-enter and finish drilling the NUR-1 pre-salt exploration well, subject to a satisfactory licence extension and necessary funding.

OUR STRATEGY

Max Petroleum's strategy is to maximise reserves, production and cash flow from its shallow, post-salt discoveries in its Blocks A&E Licence area in the Pre-Caspian Basin, while continuing to pursue the higher impact exploration potential of its pre-salt portfolio.

OPERATIONS REVIEW

The Group drilled 35 post-salt wells during the year ended 31 March 2014, including 27 appraisal wells, six development wells and two unsuccessful exploration wells.  This brings the total number of wells drilled to date by the Group since 2006 to 103, made up of 26 exploration wells (of which eight were successful), 50 appraisal wells (of which 41 were successful) and 27 development wells (of which 26 were successful). As of 19 August 2014, the Group has drilled a further three appraisal wells and one development well since 31 March 2014.

The Group has a comprehensive plan for the commercial development of its post-salt fields. For the remainder of the year ending 31 March 2015, however, the Group's planned appraisal and development drilling is subject to available financing. Additional drilling at Zhana Makat also depends on the future results of the ZMA-E8 appraisal well, testing a possible extension of the Zhana Makat field, which if successful would require further drilling to appraise and develop this part of the field.

At East Kyzylzhar I, additional drilling may be undertaken dependent on the results of current Test Production and at Baichunas West and Eskene North, further analysis of fracture stimulation tests may also justify further appraisal drilling. At Sagiz West a programme of drilling up to 20 production and injection wells is planned to be implemented over time following the progression of the field to TPP, expected in Q2 2015. At Asanketken two wells are planned to be drilled after the field obtains FFD status, expected in Q4 2014, permitting 80% of production from the field to be exported.

The Group estimates that it would need to incur approximately US$20 million in additional capital expenditure through the end of calendar year 2016 to develop the Sagiz West field, where the majority of its capital expenditures will be directed. The Group estimates that over the same period it would need to incur another US$18 million in capital expenditure to develop its other post-salt fields, including drilling a step-out appraisal well at ZMA-E8 to test the Zhana Makat South East extension. In the event that ZMA-E8 is successful, further capital expenditure would be required to move the extension into FFD.

The Group intends to fund its post-salt capital programme using cash flow from operations. However, the directors have identified a funding shortfall of approximately US$5 million through 31 December 2014 and up to an additional US$10 million during calendar year 2015 if the Group is to continue the planned discretionary post-salt capital spending programme set out above. All future capital expenditure is subject to this additional funding being available and, as of the date of this report, the absence of this additional funding in the near term has resulted in the temporary suspension of discretionary capital expenditures. The Group has incurred approximately US$8 million in capital expenditures through the four months ended 31 July 2014.

Strategic partner investment of approximately US$62.5 million

On 4 August 2014, the Group announced that it had agreed a conditional cash subscription with AGR Energy which would raise approximately US$62.5 million before expenses as consideration for the issue for 2,264,093,462 new ordinary shares at a price of 1.64p per share (the "Subscription"). Immediately following completion of the Subscription, AGR Energy would hold 51% of the Company's enlarged issued share capital. The Subscription price represents a premium of 33.9% to the closing middle market price of an ordinary share of 1.225p on 1 August 2014.

AGR Energy is a vehicle owned by the Assaubayev family established for the purpose of the Subscription. The Subscription is conditional upon a number of conditions, including approval of the Company's shareholders in a general meeting and receiving regulatory approvals from the Government in Kazakhstan.

The Subscription should enable the Group to fund its planned capital programme to develop its post-salt fields and maximise reserves and production. The Company would also be able to consider investment in other projects in Kazakhstan and across Central Asia that complement its existing activities. In addition, Max Petroleum would be in a strengthened position to attract financial or industry partners to help finish its pre-salt NUR-1 well and to secure an extension of the exploration period of its Blocks A&E Licence in western Kazakhstan to provide sufficient time to finish drilling NUR-1 and, if it is successful, the Kurzhem well. If the Subscription, or a similar infusion, was not to occur, it is likely that it would be necessary for the Group to book an impairment charge against the balance sheet carrying value of NUR-1 and associated pre-salt exploration costs.

Post-salt exploration asset impairment

Having completed the drilling of its post-salt exploration portfolio and carried out an extensive appraisal drilling programme during the year ended 31 March 2014, the Group has now largely evaluated the post-salt potential of Blocks A&E and is in a position to make a determination about the recoverability of the associated exploration and appraisal asset allocated to the post-salt, which amounted to US$64.6 million at 31 March 2014. This exploration and appraisal asset is associated with the historic development of the post-salt portfolio, including an allocation of licence acquisition costs, 3D seismic, geological and geophysical studies and capitalised interest. Given the completion of post-salt exploration drilling, the resulting 2P reserves at 31 March 2014 of 9.5 mmboe as estimated by the Group's competent person, Ryder Scott, and the limited remaining potential for the growth of post-salt reserves, the Group has performed an impairment test of the US$64.6 million exploration and appraisal asset allocated to the post-salt portfolio.

Considering the many uncertainties facing the Group, including the completion of the Subscription, which is subject to a number of conditions, and a current funding shortfall causing the temporary suspension of discretionary capital expenditures necessary to increase the reserves and production of its post-salt fields, the directors have taken the view that it is not appropriate to carry forward the US$64.6 million exploration asset related to its post-salt fields in the balance sheet. As a result, the Group has recognised a US$64.6 million non-cash impairment of its post-salt exploration and appraisal assets in its financial statements for the year ended 31 March 2014.

Zhana Makat pipeline

At Zhana Makat, the completion and commissioning of an oil export pipeline in June 2014 has reduced transportation costs for all of the production running through the Zhana Makat facility by approximately US$4.00 per barrel. Transportation of crude oil from the Borkyldakty, Sagiz West and East Kyzylzhar I fields as well as Zhana Makat through this pipeline is expected to lead to an annualised transport cost saving of approximately US$4.9 million.

Production

During the fiscal year ended 31 March 2014, the Group produced 1,423,000 bbls, or 3,899 bopd, an increase of 17% from total production of 1,221,000 bbls, or 3,346 bopd, in the prior year. The Group is currently producing approximately 3,400 bopd from fields on continuous production (Zhana Makat, Borkyldakty and Asanketken), with approximately 2,200 bopd available for export from approximately 2,800 bopd produced by fields on FFD.

Regulations in Kazakhstan 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$15 and US$25 per barrel higher than domestic prices on an after-tax basis.

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

As at 31 March 2014, Zhana Makat and Borkyldakty were on FFD, Asanketken was on TPP and Sagiz West and East Kyzylzhar I were on Test Production. The Group received regulatory approval to place Asanketken on TPP in May 2013 and the field is expected to progress to FFD later in 2014. It is expected that the East Kyzylzhar I, Baichunas West and Sagiz West fields will move from Test Production to TPP during 2015, upon which each well can operate in continuous production. The remaining two fields, Uytas and Eskene North, are in the Test Production phase but production from these fields has not been material.

Reserves and resources

As at 31 March 2014, the Group's competent person, Ryder Scott, estimated that the Group had 9.5 mmboe in proved and probable ("2P") reserves with an after-tax net present value discounted at 10% ("PV10") of US$184 million. This was a 13% decrease in 2P reserves from 10.9 mmboe as at 31 March 2013 and no change in PV10, which was US$184 million at both 31 March 2014 and 31 March 2013.  The total 2P reserves of 9.5 mmboe at 31 March 2014 was reduced by production during the period of approximately 1.4 mmboe. Ryder Scott estimated that as at 31 March 2014, the Group's total proved, probable and possible ("3P") reserves were 10.4 mmboe, down by 27% from total 3P reserves of 14.2 mmboe at 31 March 2013. The 3P reserves at 31 March 2014 had a PV10 of US$197 million, down 17% from a PV10 of US$236 million a year earlier.

Since 30 September 2013, 2P reserves, as estimated by Ryder Scott, increased by 11% from 8.6 mmboe at 30 September 2013 to 9.5 mmboe at 31 March 2014 and the equivalent PV10 increased by 32% from US$140 million to US$184 million at 31 March 2014. Since 30 September 2013, 3P reserves, as estimated by Ryder Scott, increased by 7% from 9.7 mmboe at 30 September 2013 to 10.4 mmboe at 31 March 2014 and the equivalent PV10 increased by 25% from US$157 million to US$197 million at 31 March 2014.

Total estimated 2P reserves at 31 March 2014 compared to a year earlier increased at Sagiz West, East Kyzylzhar I and Uytas and declined at Zhana Makat, Borkyldakty, Asanketken and Baichunas West. Further work is expected to be required at Uytas, Baichunas West and Eskene North to predict the likely extent of economically producible reserves. One successful well at East Kyzylzhar I, KZIE-4, was not taken into account in the analysis undertaken by Ryder Scott to estimate reserves as of 31 March 2014 as it was drilled after year-end. The Group intends to prepare the next competent person's report ("CPR") as at 30 September 2014 followed by a CPR at the end of the financial year ended 31 March 2015.

Following the extensive appraisal programme at Sagiz West in 2013 and 2014 the Group now estimates ultimate recoverable reserves from the field will be approximately 5 to 6 mmbo plus approximately 3 bcf of gas. Final results of the 3D processing and evaluation and the appraisal drilling indicate the field is more compartmentalised than originally expected and that well rates in some areas are significantly higher than in others.

The appraisal wells drilled at Uytas during the year confirmed the field has Cretaceous Aptian and Jurassic reservoirs which are capable of conventional oil production, but the productive area of the field is smaller than originally mapped. In addition, while earlier wells drilled in the field encountered hydrocarbon shows in shallower, non-conventional Cretaceous Albian reservoirs, the wells drilled during the year did not reflect a broad presence of oil saturation across the structure in these reservoirs. The requirement for standalone processing and transport facilities to be built at Uytas to handle substantial long-term production is also expected to affect the decision on the go-ahead for further development and investment at the field. The progression of the Uytas field to TPP is expected to proceed during 2015, but there is no guarantee that the funds will be available to develop the field beyond TPP to FFD. The Group is considering the option of seeking potential partners with nearby operations to work with on the development of the field.

The Group's reserves as estimated by Ryder Scott as at 31 March 2014, 30 September 2013 and 31 March 2013 are as follows:

FIELDS ON CONTINUOUS PRODUCTION

Zhana Makat

The Zhana Makat field was discovered in Block E in September 2006 and produces from Neocomian, Jurassic and Triassic reservoirs. Zhana Makat was approved for FFD in March 2012 and there are currently 28 producing wells and six water injection wells at the field. Average production from the field has increased from approximately 2,100 bopd during the year ended 31 March 2013 to approximately 2,500 bopd during the year ended 31 March 2014. Current production is approximately 2,600 bopd. 

During the year to 31 March 2014, the Group drilled five development wells, which were designed to complete the development of the field and increase daily production. Since 31 March 2014, a further development well was drilled at the field and, subject to funding, the Group plans to drill the ZMA-E8 appraisal well late in 2014 which will test a possible extension of the field to the southeast. If successful, ZMA-E8 could materially increase the size of the Zhana Makat field.

A gathering system in the southern portion of the field was completed in July 2013 to tie the new development wells into the in-field piping network. A new oil receiving and pumping terminal at Makat and a new 10 km oil pipeline connecting Zhana Makat to the Makat terminal were commissioned in June 2014. The new oil pipeline lowers the cost to transport crude oil production to the regional pipeline by approximately US$4.00 per bbl. Zhana Makat also acts as a regional hub, where oil trucked from the Borkyldakty, Sagiz West and East Kyzylzhar I fields, is processed through the field's facilities and fed through the new pipeline to the Makat terminal. The Ryder Scott estimate of 2P reserves at the field is 3.3 mmbo as at 31 March 2014.

Borkyldakty

The Borkyldakty field was discovered in Block E in February 2010 and produces from Triassic reservoirs. The field was placed on TPP in June 2011 and was approved for FFD in July 2013. Average production from the field was approximately 130 bopd during the year ended 31 March 2014 and is currently approximately 200 bopd. 

There are three producing wells at the field, including the BOR-4 development well drilled in August 2013. Crude oil from Borkyldakty is trucked 65 km to Zhana Makat where it is processed and put into the export pipeline. Since FFD approval in July 2013, 80% of the production from Borkyldakty has been sold on the export market, with the remainder being sold domestically. The Group plans to convert the non-producing BOR-2 well into a water injection well later in calendar year 2014, which should reduce operating costs at the field. The Ryder Scott estimate of 2P reserves at the field is 0.2 mmbo as at 31 March 2014.

Asanketken

The Asanketken field was discovered in Block E in March 2011 and produces from Jurassic reservoirs. The field has been producing continuously since May 2013, when it was granted TPP approval.  Average production from the four wells in the field was approximately 1,000 bopd during the year ended 31 March 2014. Current production is approximately 600 bopd following some increase in water production. 

Production from Asanketken was previously trucked approximately 210 km to the Zhamansor terminal but, since August 2013 it has been trucked to an existing terminal located approximately 40 km from the field where the oil is pumped into the KazTransOil national oil pipeline grid.  This change, combined with the installation of water disposal facilities through which all produced water has been injected into one of the wells in the field since September 2013, has lowered the field's production and transportation costs by approximately US$7 per barrel, saving the Group approximately US$400,000 per month. A new high quality 3D seismic survey was acquired over the field in the spring of 2013 and having analysed its results, subject to funding, the Group plans to drill up to two more development wells at the field subsequent to it being placed on FFD, which is expected later in 2014.  The Ryder Scott estimate of 2P reserves at the field is 1.6 mmbo as at 31 March 2014.

FIELDS IN APPRAISAL

Uytas

The Uytas field was discovered in Block A in October 2010 and has productive Cretaceous and Jurassic reservoirs at shallow depths of between 100 and 400 metres.  After the initial discovery well, three wells were drilled in 2011 and a further 14 appraisal wells were drilled in 2013.  During Test Production, wells produced at rates ranging from a few bopd up to 37 bopd, with wells in the main producing area averaging approximately 20 bopd.

The Uytas field has been shut-in since Test Production from the appraisal wells ended in 2013.  The Test Production results and the analysis of an extensive 3D seismic survey carried out over the field will provide the technical basis for moving the field to TPP status during 2015. 

At Uytas, oil has been trucked approximately 100 km to a terminal at Zhamansor, but construction of a new 40 km pipeline to the nearest terminal at Sagiz village would be an option for future production during TPP and FFD, if deemed economic. The 2P reserves for Uytas in the current Ryder Scott report of 1.1 mmbo have increased slightly from 0.9 mmbo at 31 March 2013. The requirement for standalone processing and transport facilities to be built at Uytas to handle substantial long-term production is however expected to affect the decision on the go-ahead for further development and investment at the field. The progression of the Uytas field to TPP is expected to proceed during 2015 but there is no guarantee that a decision will be made to commit funds to subsequently develop the field beyond TPP to FFD. The Group is considering the option of seeking potential partners with nearby operations to work with on the development of the field.

Sagiz West

The Sagiz West field is a Triassic discovery made in Block E in September 2011. The Group has drilled a total of 14 wells in the field to date, of which 11 have been successful. 11 appraisal wells were drilled during the year ended 31 March 2014, including four since the previous Ryder Scott reserve estimate as of 31 December 2013. The field is located approximately 30 km to the south of Zhana Makat.

During the year, the Group acquired a higher resolution 3D seismic survey across Sagiz West. This new survey has identified additional faults running along the crest of the structure which were difficult to discern previously. The new seismic survey, along with the results of drilling and testing to date, have shown the field to be a more complex and faulted/compartmentalised structure than previously estimated and where well production rates can be significantly higher in some areas than in others.

Interpretation of the new 3D seismic and the results from the first appraisal wells drilled during the year led to an initial decrease in 2P reserves from 2.54 mmboe at 31 March 2013 to 1.62 mmboe at 30 September 2013. However, since then the completion of the appraisal drilling programme resulted in a revised estimate of 2P reserves of 2.27 mmboe at 31 December 2013 and an increase to 2.63 mmboe at 31 March 2014. The Group now estimates that ultimate recoverable reserves from the field will be approximately 5 to 6 mmbo plus approximately 3 bcf of gas. The results of the 3D seismic survey and evaluation of the wells drilled to date indicate that approximately 20 further wells, including both development and injection wells, will eventually need to be drilled in order to maximise production from the field.

Development of the field will include gas or water injection for pressure maintenance in the reservoirs, as well as potentially gas production and export. Initial plans are that production will be trucked to Zhana Makat, but development plans may include an oil pipeline to be built to the Makat terminal and a gas pipeline to Zhana Makat. Current plans are to re-inject produced gas to help manage reservoir pressures but, given the possibility to export gas north to Russia or east to China and to sell in the domestic market, there are other opportunities to commercialise this asset.  Construction of facilities is expected to start later in 2014, subject to funding, and be finished by mid-2015.

Using the data from the appraisal drilling at the field and from production tests, the TPP project for Sagiz West is currently being prepared for submission to the Ministry of Energy. The current production from the field is classified as Test Production and subject to substantial variability, as individual wells are tested and recompleted in each zone every 90 days until all available zones have detailed production history. In the period between 31 March 2014 and 31 July 2014 production averaged approximately 570 bopd. The majority of this production is currently shut-in with the wells having produced for the allowed period in each zone. The Group estimates the combined productive capacity of the wells drilled to date at the Sagiz West field to be in excess of 1,000 bopd, based on production rates achieved during Test Production. The Company's best estimate for the granting of TPP, which will allow continuous production from the field to commence, is Q2 2015.

East Kyzylzhar I

The East Kyzylzhar I field, a three-way faulted closure located in Block E, was discovered in August 2011 with the KZIE-1 well. The KZIE-2 appraisal well was drilled later that year and both wells were later placed on Test Production.

KZIE-1 performed well but KZIE-2 produced with a very high water cut. The Group plans a remedial workover for KZIE-2 to improve productivity once the field has entered TPP. In 2013, additional high quality 3D seismic was carried out over the field and in 2014 three further wells were drilled. The KZIE-5 and KZIE-4 wells successfully appraised a further part of the field, while the KZIE-3 well was a dry hole. The two successful wells were put on Test Production in May and June 2014 with combined productive capacity of approximately 300 bopd. The KZIE-5 well result, in addition to the results of the 3D seismic survey during 2013, enabled Ryder Scott to increase their estimated reserves for the field to 0.5 mmbo as of 31 March 2014. The results of the successful KZIE-4 appraisal were not taken into account in this Ryder Scott reserve estimate as the well was drilled after year-end.

The Group believes there is the potential to increase the reserves estimated for the field and plans to progress East Kyzylzhar I to TPP in early 2015 and to FFD late in 2016.

Baichunas West

The Baichunas West field was discovered in Block E in September 2012, with the BCHW-1 well testing oil from the Lower Jurassic formation.  A second well drilled in the field, BCHW-2, encountered gas in the Middle Jurassic reservoir and extensive shows in the Triassic sands, over a 170 metre interval, which were however of poor quality and not able to produce at commercial rates during initial testing. The BCHW-3 appraisal well, drilled in September 2013, was unsuccessful.

The current Ryder Scott 2P reserve estimate of 0.12 mmbo is based only on reserves around the BCHW-1 well.  The Group believes there may be further upside potential in the field and is considering two additional wells for later in 2015 and the potential for fracture stimulation to improve productive rates. Oil production from Baichunas West will be trucked to Zhana Makat for any necessary processing and sales.  Current plans are to progress the Baichunas West field to TPP in early 2015 and to FFD in early 2017.

Eskene North

Eskene North is a Triassic-aged field discovered in Block E in December 2012 by the ESKN-1 well. Testing began in May 2013 and the well initially produced at indicative rates of up to 25 bopd with no water. The ESKN-1 well was treated with hydraulic fracture stimulation ("fracking") in December 2013 in an effort to improve productivity, but the results were inconclusive.

An alternative approach to fracking is also being considered to improve productivity in both the ESKN-1 well and the ESKN-2 well, which was drilled in October 2013. Progression to TPP will depend on successful stimulation of these wells, in which case it is expected that further appraisal wells would also be drilled. Ryder Scott currently considers all of the estimated Original-Oil-In-Place ("OOIP") at Eskene North to be contingent resources pending successful stimulation of one of the wells. Oil produced from Eskene North during Test Production has been trucked to Zhamansor, but in commercial development it is expected that it would be trucked to Zhana Makat for processing and sales.

PROSPECTIVE RESOURCES

Post-salt potential

In addition to the continuing appraisal of the fields discovered by the Group to date, which includes the potentially material extension to the Zhana Makat field, there are several potential new appraisal targets located within the Group's Blocks A&E Licence area, where data on reserves attributed to historic wells drilled in the Soviet era are being evaluated. Should this process conclude that there is potential to resume production from these wells and that potentially new wells could be drilled then the Ministry of Energy will be approached to grant permission for the Group to undertake further appraisal work.

Pre-salt potential

As a part of its exploration period work programme, the Group 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 Emba 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. The estimated geological chance of success for NUR-1 is 29%.

The failure to finish the NUR-1 well and reach a target depth of 7,250 metres in the summer of 2012 was a major setback for the Group. Since then two milestones have been achieved which enable a fuller understanding of the problems encountered drilling the well through the salt and which will help ensure these problems can be avoided when drilling restarts at NUR-1. The first milestone was a thorough analysis, as part of the Kazakhstan Government sponsored Technical Roundtable in early 2013, of the causes of the problems encountered when drilling the well. The second was a thorough redesign of the well programme by Halliburton which concluded, in accordance with the findings of the Technical Roundtable, that although drilling risks remain, there is no technical reason why the NUR-1 well cannot be successfully re-entered and drilled to the target depth of 7,250 metres.

The testing of the pre-salt potential of the Licence remains one of the primary objectives of the Group and there is a high degree of technical confidence that the well can be successfully drilled to target depth. Given, in particular, the support of the Government of Kazakhstan, which recognises that testing this deep play is of strategic importance to the Republic of Kazakhstan, finishing the NUR-1 well is achievable. Two significant obstacles need to be overcome, however, to enable the Group to move ahead with drilling NUR-1. Firstly, additional funding of approximately US$20 to 25 million is required, with funding for a potential follow up well also desirable in the event that NUR-1 is successful and makes a substantial commercial discovery.  Secondly, given that the exploration period of the Group's Blocks A&E expires in March 2015, an extension of the exploration period is necessary to have the time to finish drilling and to facilitate rapid follow-up appraisal drilling should this well make a discovery. Naturally, such an extension would also make an investment in the NUR-1 play more attractive to third-party investors.

A geomechanical study of the NUR-1 well conducted by Halliburton to re-evaluate the design parameters for the well was completed in June 2013 and a conceptual well design and revised drilling programme were subsequently prepared.  The existing well bore would be used to a depth of approximately 5,300 metres, where a window would be cut in the existing casing and a new well would be drilled from that point. The new programme differs from the original in that it will use higher mud weights, and it incorporates the use of "expandable liners" to create the possibility of setting an additional protective string of casing should the well again encounter any drilling problems.

Max Petroleum has signed a memorandum of understanding with Halliburton, under which they would 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. The NUR-1 re-entry plan that was designed by Halliburton was submitted to CaspiyMunaiGas, a design institute, in May 2014 and is going through the approvals process necessary before it can be used to drill the NUR-1 well to target depth.

Notwithstanding the Group's commitment to completing NUR-1, it remains subject to securing the US$20 to 25 million funding needed and successfully obtaining a licence extension prior to when the current permission expires in March 2015. Even if the funding were arranged in the near future, given  the expiry date of the exploration portion of the licence it is unrealistic to expect that the well could be completed by March 2015 because of the lead time necessary to procure a suitable rig and the time necessary to complete the drilling itself. There is no guarantee that a licence extension to complete NUR-1 beyond March 2015 will be given to the Group.

In the event that the Subscription by AGR Energy did not close, and therefore the investment of approximately US$62.5 million was not made into the Group, the directors would have to evaluate the possibility that the pre-salt assets were impaired. In that scenario, faced with the dual uncertainties of funding and a contingent licence extension in March 2015, the directors have concluded that the most prudent course of action would be to book a one-time accounting charge to impair fully the carrying value of NUR-1 and associated pre-salt exploration costs.  Under these circumstances, the Group would most likely take a non-cash impairment charge of approximately US$113 million. This charge would not affect the results for the year ending 31 March 2014, but instead would be recognised in the financial statements for the year ending 31 March 2015. Therefore, the successful completion of the Subscription is a key assumption in continuing to recognise the US$113 million costs associated with the pre-salt in the Group's balance sheet at 31 March 2014 and thereafter.

Finishing the well and evaluating this high potential target remains a top priority for the Group. Given the transformational potential of a deep, pre-salt discovery, the Group believes it has a realistic chance of attracting the necessary funding, and securing the licence extension required to finish drilling NUR-1.

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

The Group has eight post-salt discoveries with two fields producing under FFD (Zhana Makat and Borkyldakty), one field under TPP (Asanketken), and the remaining fields at varying stages of appraisal and development. As the Group continues to appraise and develop its discoveries they progress from Test Production into TPP, where they are able to resume continuous production, and then move from TPP to FFD, where 80% of the production is available to sell on export markets for a substantially higher price per barrel. The Group is currently producing approximately 3,400 bopd from fields on continuous production (Zhana Makat, Borkyldakty and Asanketken), which generates over US$8 million per month in revenue. The Group estimates the combined productive capacity of the wells drilled to date at the Sagiz West field to be in excess of 1,000 bopd, based on production rates achieved from these wells before some of them were shut-in when their Test Production periods ended earlier in 2014. The TPP project for Sagiz West is currently being prepared for submission to the Ministry of Energy. The Company's best estimate for the granting of TPP, which will allow continuous production from the Sagiz West field to commence, is Q2 2015. From now until then, the Group expects its total production to average around 3,400 bopd from wells drilled to date. The directors believe that progression of the Sagiz West field into TPP and the commencement of continuous production of that field is an important milestone for the Group and the Board is working to expedite the progress of the application through the required official approvals as quickly as possible.

The Group is implementing a cost-cutting initiative to reduce administrative costs. The initiative recognises the Group's shift from exploration and development to primarily production with a focus on maximising cash flow and is focused on a reduction in corporate overhead, including downsizing its London office and closing its Houston office, scheduled for Q3 2014. The cost-cutting measures are expected to generate recurring annual savings of approximately US$4 million in administrative costs.

As of 19 August 2014, the Group has US$85.9 million outstanding under the Sberbank Loan. The Group was in technical breach of certain banking covenants related to production and reserves at 31 March 2014. Accordingly, the entire loan amount has been classified within current liabilities in the Group balance sheet. The Group is currently working with Sberbank to reset the production and reserves covenants to reflect the lowered expectations of the Group following the Ryder Scott 2P reserves estimate of 9.5 mmboe as at 31 March 2014. The Group is current on all interest and principal payments due under the Sberbank Loan, which have been made when due with no late payments.

After Sagiz West commences TPP, expected in Q2 2015, the Group estimates that it would need to incur approximately US$20 million in additional capital expenditure through the end of calendar year 2016 to develop the field, including drilling 13 additional wells and constructing ancillary facilities and infrastructure necessary to advance the field through TPP. An additional US$10 million is budgeted for the subsequent development of Sagiz West after FFD status is achieved, estimated for 2017. The development of Sagiz West will enable the field to become a substantial production asset. The Group estimates that it would need to incur a further US$18 million in capital expenditure to develop its other post-salt fields through 31 December 2016, including drilling a step-out appraisal well at ZMA-E8 to test the Zhana Makat South East extension. In the event that ZMA-E8 is successful, further capital expenditure would be required to develop the extension and achieve FFD status. Future capital requirements can be difficult to predict accurately and can be materially impacted by the results of the Group's ongoing evaluation of its current post-salt discoveries.

The Group intends to fund its post-salt capital programme using cash flow from operations. However, if the Group is to continue the planned discretionary post-salt capital programme set out above, the directors have identified an additional capital requirement of US$5 million through 31 December 2014 and up to an additional US$10 million during calendar year 2015.

In May 2013, the Group received Kazakhstan regulatory approval of an extension to the exploration period of the Blocks A&E Licence that allowed the Group to continue drilling the NUR-1 well on the Emba B prospect until March 2015. The extension also provided the Group with an option to drill the Kurzhem well on the Emba A prospect in the event that NUR-1 was successful. The Group estimates it will cost approximately US$20 to $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. Given the lead time necessary to procure a suitable rig and the time necessary to complete the drilling itself, a further licence extension beyond March 2015 is now also required in order to finish drilling NUR-1.

The capital infusion arising from the Subscription with AGR Energy of approximately US$62.5 million should enable the Group to fund its planned capital programme to develop its post-salt fields and maximise reserves and production. In addition, Max Petroleum would be in a strengthened position to attract financial or industry partners to help finish its pre-salt NUR-1 well and to secure an extension of the exploration period of its Blocks A&E Licence to enable it to have time to finish drilling NUR-1 and, if it is successful, the Kurzhem well. Completion of the Subscription is subject to a number of conditions, including approval by the Company's shareholders and receiving regulatory approvals from the Government in Kazakhstan.

The risk that the necessary approvals to complete the Subscription are not received creates an uncertainty about whether the Subscription proceeds of US$62.5 million will be received by the Group. In the event that the necessary approvals are not received and the Subscription (or a similar infusion) does not proceed, there is an uncertainty whether additional debt or equity financing will be available. Further, the Group is due to make another US$13.1 million of principal payments under the Sberbank Loan through 31 March 2015, comprising US$3.1 million in September 2014, US$3.3 million in December 2014, and US$6.7 million in March 2015. Thereafter principal repayments are US$6.6 million per quarter through November 2017. In the event that no additional funding is procured, it is expected the financial constraints imposed on the Group will necessitate the continued suspension of its capital programme in order for it to continue to meet its obligations under the Sberbank Loan. Based on the Group's cash flow forecasts and assuming the suspension of its capital programme, the directors believe that the Group will be able to continue servicing its interest and principal payments under the Sberbank Loan as they fall due. 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.

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 Loan, and other potential sources of debt and equity capital lead to 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 financial statements.

RESULTS FOR THE YEAR

The Group recorded a loss of US$76.8 million, or US$0.04 per ordinary share, for the year ended 31March 2014, compared to a loss of US$10.1 million, or US$0.01 per ordinary share, during the prior year. This loss included a non-cash impairment charge for the Group's post-salt exploration asset of US$64.6 million. No dividends have been paid or proposed for the year (2013: none).

Revenue

The Group generated US$100.4 million in revenue from the sale of approximately 1,370,000 bbls of crude oil during the year, or US$73.29 per bbl (2013: US$93.3 million on sales of 1,234,000 bbls of crude oil, or US$75.64 per bbl). The Group achieved export sales of 728,000 bbls generating US$75.4 million in revenue, or US$103.49 per bbl (2013: 620,000 bbls generating US$64.1 million in revenue, or US$103.51 per bbl). Domestic sales totalled 642,000 bbls of crude oil generating US$25.1 million in revenue, or US$39.04 per bbl (2013: 614,000 bbls generating US$29.2 million in revenue, or US$47.54 per bbl).

Sales revenue grew 8% to US$100.4 million (2013: US$93.3 million) as a result of an 11% increase in sales volumes, partially offset by weaker prices received on domestic sales. During the year ended 31 March 2014, the Group drilled five development wells at the Zhana Makat field and completed a gathering system in the southern portion of the field to tie in the new wells, contributing to an increase in the field's average daily production from approximately 2,100 bopd during the year ended 31 March 2013 to approximately 2,500 bopd during the year ended 2014. The Group also generated increased production at Asanketken following the commencement of TPP in May 2013, which enabled continuous production from the field.

Production from the Group's discoveries in Test Production and TPP is sold exclusively in Kazakhstan on the domestic market until each field is approved for FFD. FFD approval gives the Group the right to sell 80% of a field's production on the export market, enabling it to achieve a substantially higher selling price per barrel.  Export sales are subject to export rent tax, export customs duty and higher rates of mineral extraction tax and transportation costs, but the overall after-tax netbacks are expected to be US$15 to 25 per bbl higher than comparable domestic sales.

Cost of sales

Cost of sales increased by 12% from US$70.1 million, or US$56.87 per bbl, in the year ended 31 March 2013 to US$78.9 million, or US$57.56 per bbl, in the year ended 31 March 2014. Cost of sales includes depreciation, depletion and amortisation of US$24.8 million (2013: US$21.8 million). Cost of sales before depreciation, depletion and amortisation was US$54.0 million, or US$39.44 per bbl (2013: US$48.3 million, or US$39.17 per bbl). This includes production costs of US$12.2 million, or US$8.87 per barrel (2013: US$11.6 million, or US$9.42 per bbl), selling and transportation costs of US$14.8 million, or US$10.78 per bbl (2013: US$14.3 million, or US$11.55 per bbl), and taxes on the production and sale of hydrocarbons of US$27.1 million, or US$19.79 per bbl (2013: US$22.4 million, or US$18.19 per bbl). The taxes include export rent tax, export customs duty and mineral extraction tax. In April 2013, the export customs duty on crude oil was raised from US$40 to 60 per tonne, an increase of approximately US$2.70 per bbl. Since 31 March 2014 the applicable rate has increased further to US$80 per tonne.

On a per barrel basis, production costs and selling and transportation costs decreased by 6% and 7%, respectively, as several operational cost reduction initiatives implemented during the year began to be reflected in the Group's results. These initiatives included reducing the distance that oil is trucked from Asanketken by using a nearby loading terminal and reducing water haulage costs by installing water disposal facilities at the Asanketken field to deal with the associated water extracted during oil production. Transportation costs are expected to decrease further over the forthcoming year, following the commissioning of a new pipeline and terminal facility in June 2014, which connects the Zhana Makat field to the regional oil pipeline approximately 10 km away.

After cost of sales, gross profit was US$21.6 million, or US$15.73 per bbl (2013: US$23.2 million, or US$18.77 per bbl).

Post-salt exploration asset impairment

Having completed the drilling of its post-salt exploration portfolio and carried out an extensive appraisal drilling programme during the year ended 31 March 2014, the Group has now largely evaluated the post-salt potential of Blocks A&E and is in a position to make a determination about the recoverability of the associated exploration and appraisal asset allocated to the post-salt, which amounted to US$64.6 million at 31 March 2014. This exploration and appraisal asset is associated with the historic development of the post-salt portfolio, including an allocation of licence acquisition costs, 3D seismic, geological and geophysical studies and capitalised interest. Given the completion of post-salt exploration drilling, the resulting 2P reserves at 31 March 2014 of 9.5 mmboe as estimated by the Group's competent person, Ryder Scott, and the limited remaining potential for the growth of post-salt reserves, the Group has performed an impairment test of the US$64.6 million exploration and appraisal asset allocated to the post-salt.

Considering the many uncertainties facing the Group, including the Subscription which is subject to shareholder approval and approval of the Government of Kazakhstan, and a current funding shortfall causing the temporary suspension of discretionary capital expenditures necessary to increase the reserves and production of its post-salt fields, the directors have taken the view that it is not appropriate to carry forward the US$64.6 million exploration asset related to its post-salt fields in the balance sheet. As a result, the Group has recognised a US$64.6 million impairment of its post-salt exploration and appraisal assets in its financial statements for the year ended 31 March 2014.

Restructuring costs

The Group has established a restructuring provision of US$3.8 million as at 31 March 2014, for severance and other transitional expenses associated with various cost reduction measures. These include the closure of the Group's Houston office, the reduction in size and cost of the Group's London office, and a reduction in senior management and administrative personnel across the Group's operations.

Operating loss

The Group's operating loss for the year was US$65.8 million (2013: US$1.2 million) which is stated after non-cash  impairment losses of US$64.6 million, administrative costs of US$14.9 million (2013: US$17.3 million), including share-based payment expense of US$2.7 million (2013: US$3.6 million), and exploration and appraisal costs of US$4.1 million (2013: US$7.0 million), including dry hole costs of US$1.5 million and a US$2.2 million write down of inventories of drilling supplies. The Group's operating loss includes aggregate depreciation, depletion and amortisation of US$25.1 million (2013: US$22.1 million).

Adjusted EBITDA, defined as profit/(loss) before finance income, finance expense, income tax expense, depreciation, depletion and amortisation, share-based payment expense, exploration and appraisal costs, restructuring costs and impairment losses, increased by 9% from US$31.5 million during the year ended 31 March 2013 to US$34.5 million during the current fiscal year. This primarily reflects the increase in production and sales volumes during the year.

Taxation

Income tax expense for the year was US$5.1 million, comprising US$4.4 million of deferred tax and US$0.7 million of current tax (2013: US$4.9 million of deferred tax and US$0.1 million of current tax).

The US$0.7 million of current tax relates to tax claims made by the Kazakhstan tax authorities in relation to the tax years ended 31 December 2007 and 31 December 2008. While the Group considers the tax claims are without merit and is in the process of appealing the claims with the relevant tax authorities and through the courts, in accordance with the decisions of the courts to date, the Company has paid the 2007 claim in full and has paid a portion of the 2008 claim. The Group has recognised liabilities in these financial statements for the expected remaining cash outflows if it is unsuccessful in its appeals. The aggregate expense recognised in these financial statements in relation to the tax claims is US$1.8 million, comprising US$0.7 million of tax, US$0.7 million of interest and US$0.4 million of penalties, recorded within income tax expense, finance costs and administrative expenses, respectively.

Before taking account of the US$64.6 million impairment of the Group's post-salt exploration and appraisal assets, the Group recognised a deferred tax expense of US$9.6 million, including US$6.8 million related to the effect of the devaluation of the Kazakhstan tenge on future fixed asset tax deductions and brought forward tax losses. The deferred tax effect of the impairment is US$4.5 million, resulting in a net US$5.1 million deferred tax expense for the year.

The Group's net deferred tax liability of US$9.2 million arises primarily as tax allowances received to date in Kazakhstan for exploration and appraisal expenditure, oil and gas properties and property, plant and equipment have exceeded the depreciation, depletion and amortisation charged in the financial statements. 

FINANCING AND CAPITAL STRUCTURE

Cash flow

The Group's cash generated from operations was US$34.0 million (2013: US$40.4 million), consisting of net revenue from the production and sale of crude oil, offset by the Group's general and administrative expenses. Before taking working capital movements into account, operating cash flow was US$34.9 million (2013: US$31.5 million).

Net cash used in investing activities was US$47.6 million (2013: US$46.4 million), which mainly relates to capital expenditure on the Group's exploration, appraisal and development programmes, including 35 post-salt wells drilled during the year.

Net cash generated from financing activities was US$13.1 million (2013: US$6.4 million), comprising US$25.4 million of proceeds from the drawdown of the Sberbank Loan, offset by US$2.0 million of loan repayments and US$10.3 million of interest and finance costs (2013: US$66.6 million of proceeds from borrowings offset by US$50.0 million repaid to Macquarie, US$3.4 million paid to bondholders, US$1.0 million of debt issuance costs relating to the Sberbank Loan and US$5.8 million of interest and finance costs).

As at 31 March 2014, the Group held unrestricted cash balances of US$0.5 million (2013: US$1.8 million).

Borrowings

In December 2012, the Group closed a new secured US$90 million credit facility with Sberbank (the "Sberbank Loan") as part of a comprehensive restructuring of its outstanding debt facilities, comprising the refinancing of its previous credit facility with Macquarie Bank Limited ("Macquarie" and the "Macquarie Facility") and the restructuring of its convertible bonds (the "Bonds"). In August 2013, the Group received the requisite Kazakhstan regulatory approvals and the remaining outstanding Bonds, which had a carrying value of US$26.7 million, were converted into ordinary shares of the Company.

During the year ended 31 March 2014, the Group drew down the remaining balance of the Sberbank Loan to fund capital expenditures on the Group's post-salt appraisal and development programme. In March 2014, the Group commenced quarterly repayments of the Sberbank Loan, which matures in November 2017.

Since 30 September 2013, the Group has been in technical breach of certain banking covenants related to production and reserves. The Group is currently working with Sberbank to reset the production and reserves covenants to reflect the lowered expectations of the Group, following the Ryder Scott estimation of total 2P reserves of 9.5 mmboe as at 31 March 2014.

The Group is current on all interest and principal payments due under the Sberbank Loan, which have been made when due with no late payments.

Share capital

During the year ended 31 March 2014, the Company issued 357,571,134 ordinary shares as a result of the mandatory conversion of the remaining outstanding Bonds and accrued interest into shares at a price of 5p per share. The issued ordinary share capital of the Company following this allotment consisted of 2,175,305,483 ordinary shares with voting rights attached (one vote per share).

Share options

At 31 March 2014, 194.5 million options were outstanding with a weighted average exercise price of 7.2p (2013: 210.3 million options with a weighted average exercise price of 7.5p).

As a result of the employee terminations made as part of the Group's cost-cutting initiative, 8.7 million unvested options held by leavers were forfeited during the year ended 31 March 2014, with a further 16.3 million unvested options due to be forfeited after 31 March 2014 as the affected employees leave the Group. In addition, 4.7 million vested options held by the affected leavers are due to expire within 12 months of their leaving dates, if unexercised.

Subsequent to 31 March 2014, additional options to subscribe for 89 million new ordinary shares of the Company were granted to the Directors, officers and certain employees of the Group on 27 May 2014 at an exercise price of 1.2p per share, of which one third are exercisable in equal amounts on the first, second and third anniversaries of the date of grant. The options have a term of four years and any unexercised options will expire on 27 May 2018.

CAPITAL EXPENDITURE

Group capital expenditures for the year on an accruals basis totalled US$59.4 million (2013: US$48.3 million), comprising US$10.7 million for exploration and appraisal expenditure (2013: US$31.0 million), US$39.9 million for the development of oil and gas properties (2013: US$13.8 million) and US$8.8 million for property, plant and equipment (2013: US$3.5 million).

Exploration and appraisal expenditure of US$10.7 million includes US$1.5 million relating to two post-salt exploration wells drilled during the year, US$1.9 million related to the continued appraisal of the Eskene North discovery and US$6.0 million of capitalised borrowing costs (2013: US$31.0 million, including US$13.8 million relating to the NUR-1 pre-salt well, US$9.2 million relating to five post-salt exploration wells and US$7.1 million of capitalised borrowing costs).

Oil and gas development expenditure of US$39.9 million includes US$33.4 million relating to the cost of 33 post-salt appraisal and development wells drilled during the year and US$6.5 million of capitalised Geological and Geophysical ("G&G") costs (2013: US$13.8 million, including the cost of three post-salt appraisal and development wells and US$6.4 million of capitalised G&G costs).

Expenditure of US$8.8 million on property, plant and equipment includes the cost of constructing the Group's new oil terminal at Makat, the associated pipeline from the Zhana Makat field, the gathering system implemented in the southern portion of the Zhana Makat field to tie-in new wells, as well as appraisal and test production facilities across the Group's post-salt fields.

MAX PETROLEUM PLC

CONSOLIDATED INCOME STATEMENT

For the year ended 31 March 2014

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME

For the year ended 31 March 2014

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED BALANCE SHEET

At 31 March 2014

(in thousands of US$)

MAX PETROLEUM PLC

CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

For the year ended 31 March 2014

(in thousands of US$)

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

MAX PETROLEUM PLC

CONSOLIDATED CASH FLOW STATEMENT

For the year ended 31 March 2014

(in thousands of US$)

MAX PETROLEUM PLC

NOTES TO THE FINANCIAL INFORMATION

For the year ended 31 March 2014

1. General information

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

The Company is a public limited company incorporated and domiciled in the United Kingdom, quoted on AIM and listed on the Kazakhstan Stock Exchange ("KASE").  The address of its registered office is Fourth Floor, Ergon House, Dean Bradley Street, London, SW1P 2AL, 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 2014 or 2013, but it is derived from those accounts. Statutory accounts for 2013 have been delivered to the Registrar of Companies and those for 2014 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 2014 accounts, whilst unqualified, contained an emphasis of matter which drew attention to the existence of a material uncertainty which may cast significant doubt about the Company's ability to continue as a going concern, for further details see note 3. The auditors' report on the 2013 accounts contained no emphasis of matter.

3. Going concern

The Group's business activities, together with the factors likely to affect its future development, performance and position are set out in the Business Review section of this announcement. The financial position of the Group, its cash flows, liquidity position and borrowing facilities are described in the Liquidity and Capital Resources section of this announcement.

As explained in the Business Review, the Group has a comprehensive plan for the commercial development of its post-salt fields in order to maximise reserves, production and cash flow. However, in order to fund the planned post-salt appraisal and development programme, the directors have identified an additional capital requirement of US$5 million through 31 December 2014 and up to an additional US$10 million during calendar year 2015. As a result, the Group has currently suspended appraisal and development drilling in order to continue to meet its obligations under the Sberbank Loan (see note 13).

Based on the Group's cash flow forecasts and assuming the suspension of its capital programme, the directors believe that the Group will be able to continue servicing its interest and principal payments under the Sberbank Loan as they fall due. 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.

As explained in note 13, the Group was in technical breach of certain banking covenants related to production and reserves at 31 March 2014. Accordingly, the entire loan amount has been classified within current liabilities in the Group balance sheet. The Group is currently working with Sberbank to reset the production and reserves covenants to reflect the lowered expectations of the Group following the Ryder Scott 2P reserves estimate of 9.5 mmboe as at 31 March 2014. The Group is current on all interest and principal payments due under the Sberbank Loan, which have been made when due with no late payments.

As explained in note 22, on 4 August 2014 the Group announced that it had agreed a conditional cash subscription with AGR Energy No. 1 Limited ("AGR Energy") which would raise approximately US$62.5 million before expenses (the "Subscription"). The Subscription would enable the Group to fund its planned capital programme to develop its post-salt fields and maximise reserves and production. The Subscription is conditional upon a number of conditions, including approval of the Company's shareholders and receiving regulatory approvals from the Government in Kazakhstan. The risk that the necessary approvals to complete the Subscription are not received creates an uncertainty about whether the Subscription proceeds of approximately US$62.5 million will be received by the Group. In the event that the necessary approvals are not received and the Subscription (or a similar infusion) does not proceed, there is an uncertainty whether additional debt or equity financing will be available.

The directors have concluded that the combination of these circumstances represents a material uncertainty that may cast significant doubt about the Group's ability to continue as a going concern.

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 Loan, 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 financial statements.

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 head office is in London, United Kingdom, with the Group's operational activities wholly focused in the Republic of Kazakhstan, supported by a technical team in Houston, USA. The Group is in the process of closing the Houston office (see note 15).

Revenue

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

Revenue from two customers each individually exceeded 10% of the Group's consolidated revenue, amounting to US$75.4 million and US$17.6 million, (2013: sales to three customers of US$53.4 million, US$16.8 million and US$10.7 million).

Non-current assets

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

5. Cost of sales

The cost of crude oil inventories recognised as an expense and included in cost of sales amounted to US$33.7 million (2013: US$30.3 million).

6. Impairment losses

Post-salt exploration asset impairment

Having completed the drilling of its post-salt exploration portfolio and carried out an extensive appraisal drilling programme during the year ended 31 March 2014, the Group has now largely evaluated the post-salt potential of Blocks A&E and is in a position to make a determination about the recoverability of the associated exploration and appraisal asset allocated to the post-salt, which amounted to US$64.6 million at 31 March 2014. This exploration and appraisal asset is associated with the historic development of the post-salt portfolio, including an allocation of licence acquisition costs, 3D seismic, geological and geophysical studies and capitalised interest. Given the completion of post-salt exploration drilling, the resulting 2P reserves at 31 March 2014 of 9.5 mmboe as estimated by the Group's competent person, Ryder Scott, and the limited remaining potential for the growth of post-salt reserves, the Group has performed an impairment test of the US$64.6 million exploration and appraisal asset allocated to the post-salt.

Considering the many uncertainties facing the Group, including the Subscription (see note 22) which is subject to a number of conditions, including shareholder approval and approval of the Government of Kazakhstan, and a current funding shortfall causing the temporary suspension of discretionary capital expenditures necessary to increase the reserves and production of its post-salt fields, the directors have taken the view that it is not appropriate to carry forward the US$64.6 million exploration asset related to its post-salt fields in the balance sheet. As a result, the Group has recognised a US$64.6 million impairment of its post-salt exploration and appraisal assets in its financial statements for the year ended 31 March 2014.

7. Finance income

8. Finance costs

During the year ended 31 March 2014 other finance costs included US$0.7 million of interest related to the Transfer Pricing Tax Claims (note 9). During the year ended 31 March 2013 other finance costs included US$1.4 million of fees relating to the refinancing of the Group's borrowings in December 2012.

Interest expense of US$6.0 million (2013: US$7.1 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% (2013: 10%) to the average cumulative expenditure on such assets. The borrowing costs capitalised are included in 'additions' to intangible assets - exploration and appraisal expenditure. 

9. 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 within cost of sales (see note 5).

The tax on the Group's loss before tax differs from the theoretical amount that would arise using the UK statutory rate of 23% (2013: 24%) applicable to the loss of the Group, as follows:

Transfer Pricing Tax Claims

The Kazakhstan tax authorities have carried out transfer pricing tax audits of Max Petroleum'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 arm's-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 approximately US$0.7 million and US$1.3 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. The Group is in the process of appealing the Transfer Pricing Claims with the relevant tax authorities and through the courts. In accordance with the decisions of the courts to date, the Company has paid the 2007 claim in full and has paid a portion of the 2008 claim. The unpaid portion of the 2008 claim is US$1.0 million, of which US$0.8 million has been provided for in these financial statements at 31 March 2014. The aggregate expense recognised in these financial statements is US$1.8 million, comprising US$0.7 million of tax, US$0.7 million of interest and US$0.4 million of penalties.

10. Loss for the year

Loss for the year is stated after charging/(crediting):

Exploration and appraisal costs for the year ended 31 March 2014 include a US$2.2 million write down of inventories of drilling supplies. Exploration and appraisal costs for the year ended 31 March 2013 include a loss of US$1.1 million which arose on the disposal of inventories of drilling supplies.

11. Intangible assets - exploration and appraisal expenditure

Included within exploration and appraisal expenditures at 31 March 2014 was a decommissioning asset of US$0.6 million (2013: US$0.6 million).

Intangible exploration and appraisal assets comprise the costs of acquiring the Group's Blocks A&E Licence, gathering and interpreting 3D seismic data, carrying out geological and geophysical studies, identifying and high-grading leads and maturing two portfolios of exploration prospects: a post-salt inventory and a pre-salt inventory. In addition, exploration and appraisal assets include the costs of drilling exploratory wells where further work is being undertaken on geological and geophysical assessment or the field's commercial or technical viability is yet to be determined, as well as capitalised interest.

Post-salt exploration and appraisal assets

Having completed the drilling of its post-salt exploration portfolio and carried out an extensive appraisal drilling programme during the year ended 31 March 2014, the Group has now largely evaluated its post-salt potential and must transfer a portion of the costs associated with developing the post-salt exploration portfolio into oil and gas properties (note 12). The allocation of historic non-drilling exploration and appraisal costs between the post-salt and pre-salt portfolios has been determined based on the Group's estimates of the relative expected values of the respective portfolios at the time they were developed. The expected values incorporate an assessment of the risk of each portfolio. The result of the allocation is that historic costs of US$84.0 million, which at 31 March 2014 have a carrying value of US$64.6 million after deducting accumulated amortisation, are allocated to the Group's post-salt assets and are transferred to oil and gas properties.

IFRS 6 requires that when costs are transferred from exploration and appraisal assets that they are tested for impairment prior to transfer. Considering the many uncertainties facing the Group, including the Subscription (see note 22) which is subject to a number of conditions, including shareholder approval and approval of the Government of Kazakhstan, and a current funding shortfall causing the temporary suspension of discretionary capital expenditures necessary to increase the reserves and production of its post-salt fields, the directors have taken the view that it is not appropriate to carry forward the US$64.6 million exploration asset related to its post-salt fields in the balance sheet. As a result, the Group has recognised a US$64.6 million impairment of its post-salt exploration and appraisal assets in its financial statements for the year ended 31 March 2014.

Pre-salt exploration and appraisal assets

The remaining US$118.6 million carrying value of the intangible exploration and appraisal asset at 31 March 2014 is substantially dependent on the outcome of the Group's pre-salt exploration programme. The Group is required to assess at each reporting date whether there are any indications its exploration and appraisal assets are impaired. This assessment includes consideration of whether rights to explore in an area have expired, or will expire in the near future without renewal and whether further exploration and appraisal activities are planned or budgeted.

Due to financial constraints, the drilling of the NUR-1 pre-salt well has been suspended since July 2012 when the Group encountered anomalously high pressures drilling through a salt layer. During the year ended 31 March 2014, the Group has carried out a geomechanical study to examine how best to complete the NUR-1 well and overcome potential engineering challenges. The conclusion of the study is that the existing well bore can be used to complete drilling to target depth provided certain modifications are made to the well design.

Notwithstanding the Group's commitment to completing NUR-1, it remains subject to securing the US$20 to 25 million funding needed and successfully obtaining a licence extension when the current permission expires in March 2015. Even if the funding were arranged in the near future, given that the exploration portion of the licence is due to expire in March 2015, it is unrealistic to expect that the well could be completed by March 2015 given the lead time necessary to procure a suitable rig, as well as the time necessary to complete the drilling itself. There is also no guarantee that a licence extension to complete NUR-1 beyond March 2015 will be given to the Group.

In the event that the Subscription (see note 22) by AGR Energy did not close, because one or more necessary conditions were not met, and therefore the investment of approximately US$62.5 million was not made into the Group, the directors would have to make an evaluation about the possibility that the pre-salt assets were impaired as a result. Faced with the dual uncertainties of funding and a contingent licence extension in March 2015, the directors have concluded that the most prudent course of action would be to book a one-time accounting charge to fully impair the carrying value of NUR-1 and associated pre-salt exploration costs. Accordingly, under these circumstances, the Group would most likely make an impairment charge amounting to US$113.0 million. This charge would not affect the results for the year ending 31 March 2014, but instead would be recognised in the financial statements for the year ending 31 March 2015. Therefore, the successful completion of the Subscription is a key assumption in continuing to recognise the costs associated with the pre-salt in the Group's balance sheet at 31 March 2014 and thereafter.

12. Oil and gas properties

Included within oil and gas properties at 31 March 2014 was a decommissioning asset of US$2.3 million (2013: US$1.0 million).

The Group's oil and gas properties have been pledged to Sberbank to secure the Group's borrowings (note 13).

The Group assesses at each reporting date whether there are any indications that its oil and gas properties and associated property, plant and equipment are impaired. Where an indicator of impairment exists, a formal estimate of recoverable amount is made, which is determined as the higher of fair value less costs of disposal and value in use.

The Group's proved and probable ("2P") reserves decreased from 10.9 mmboe at 31 March 2013 to 9.5 mmboe at 31 March 2014 and proved, probable and possible reserves ("3P") decreased from 14.2 mmboe to 10.4 mmboe. This decrease in reserves is considered to be a potential indicator of impairment and therefore an impairment test has been performed at 31 March 2014.

As there is no readily available market for the Group's oil and gas properties, fair value is derived as the net present value of the estimated future cash flows arising from the continued use of the assets, incorporating assumptions that a typical market participant would take into account.

The value in use of an oil and gas property is generally lower than its fair value less costs of disposal as value in use reflects only those cash flows expected to be derived from the asset in its current condition. Fair value less costs of disposal includes appraisal and development expenditure that a market participant would consider likely to enhance the productive capacity of an asset and optimise future cash flows. Consequently, the Group determines recoverable amount based on fair value less costs of disposal.

Fair value less costs of disposal is based on the estimates of proved, probable and possible reserves, future production and future net income performed by Ryder Scott, the Group's competent person, as of 31 March 2014. This assessment incorporates the use of estimates and assumptions, such as long-term oil prices, discount rates, operating costs, future capital requirements, decommissioning costs, exploration potential, and reserves. These estimates and assumptions are subject to risk and uncertainty. The estimates of fair value less costs of disposal meet the definition of level three fair value measurements as they are determined from unobservable inputs.

The result of the impairment test indicate that the recoverable amounts of the Group's oil and gas properties and associated property, plant and equipment exceed their carrying values and therefore there is no impairment.

The key assumptions used in the impairment test were as follows:

·      Oil prices : these 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 exported and 20% is sold domestically. Export oil prices are based on a Brent forward price curve for the forthcoming six years and thereafter inflated at 2% per annum. The weighted average export price used was US$93 per bbl. Domestic oil prices are based on a forecast of US$45 per bbl during 2014, US$48 per bbl in 2015 and thereafter inflated at 2% per annum. The weighted average domestic price used was US$49 per bbl.

·      Reserves : it is assumed the 3P reserves of 10.4 mmboe are extracted over the period from 2014 to 2023 in accordance with the production profile set out in the Ryder Scott report.

·      Capital expenditure : it is assumed that the Group carries out US$65 million of appraisal, development and facilities expenditure necessary to advance the Group's discoveries to full field development and realise the 3P reserves over the life of each field. This expenditure covers the period from April 2014 to December 2023.

·      Discount rate : a post-tax discount rate of 10% has been used.

13. Borrowings

The fair value of the Group's bank borrowings at 31 March 2014 approximates to their gross carrying value of US$88.0 million (2013: US$64.6 million). The fair value of the PIK notes at 31 March 2013, determined by reference to the published closing price quotation from the Channel Islands Stock Exchange on that date, was US$19.4 million.

Bank borrowings

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

The material provisions of the Sberbank Loan 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.

During the year ended 31 March 2014 the remainder of the Sberbank Loan was drawn down in its entirety and the first quarterly amortisation payment was made, leaving US$88 million outstanding as at 31 March 2014. 

At the point of initial recognition, the Group incurred debt issuance costs of US$1.0 million, comprising a facility fee of US$0.9 million and directly associated legal fees of US$0.1 million, which were deducted from the liability and are spread over the life of the Sberbank Loan as part of the finance cost, using the effective interest rate method. The overall finance cost on the Sberbank Loan for the year ended 31 March 2014 was calculated using an average effective interest rate of 11.3% (2013: 11.3%).

A reconciliation of the amounts outstanding on the Sberbank Loan is as follows:

The Group was in technical breach of certain banking covenants related to production and reserves at 31 March 2014. Accordingly, the entire loan amount has been classified within current liabilities in the Group balance sheet. The Group is currently working with Sberbank to reset the production and reserves covenants to reflect the lowered expectations of the Group following the Ryder Scott 2P reserves estimate of 9.5 mmboe as at 31 March 2014. The Group is current on all interest and principal payments due under the Sberbank Loan, which have been made when due with no late payments.

During the year ended 31 March 2013, the Group used the proceeds from the Sberbank Loan to pay Macquarie US$50 million in full and final settlement of the US$52.2 million outstanding under the Macquarie Facility. The cancellation of the amounts outstanding under the Macquarie Facility resulted in a gain of US$2.2 million, recognised in the income statement as part of finance income for the year ended 31 March 2013. 

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

Convertible bonds and PIK notes

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 bore interest at 6.75% per annum, payable semi-annually, and were convertible at a price of 32p per ordinary share, with a fixed exchange rate of US$1.49 to £1. The holders of the Bonds (the "Bondholders") had a right to convert the Bonds through to final maturity on 8 September 2013. The Bonds were publicly traded on the Channel Islands Stock Exchange.

The Group did not pay the US$2.9 million semi-annual coupon interest due 8 September 2012, having previously obtained written assurances from holders representing greater than 75% of the Bonds to defer the coupon payment pending a broader restructuring of the Group's outstanding debt.

In December 2012, as part of a comprehensive restructuring of its outstanding debt facilities, the Bondholders agreed to exchange their Bonds for a combination of cash and ordinary shares (the "Bond Restructuring"). The US$2.9 million of interest due on the Bonds on 8 September 2012 was capitalised and added to the outstanding principal amount of the Bonds of US$85.6 million, with effect from 8 September 2012. A further US$1.7 million of interest, covering the period from 8 September 2012 to 19 December 2012, was also capitalised and added to principal, resulting in a revised principal of US$90.2 million at the date of the Bond Restructuring.

Pursuant to the terms of the Bond Restructuring, on 20 December 2012, the Bondholders exchanged the revised outstanding principal of US$90.2 million for the following:

·      708,999,985 ordinary shares.

·      PIK notes with a principal amount of US$26.7 million.

·      Promissory notes with a principal amount of US$3.4 million.

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 the 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 in September 2013 (note 17).

The promissory note principal of US$3.4 million, plus interest accrued at a rate of 6.75% per annum, was settled in cash in March 2013.

The Bond Restructuring in December 2012 was deemed to be a substantial modification, triggering a debt extinguishment and recognition of new debt and equity under the requirements of IAS 39 Financial Instruments Recognition and Measurement. In accordance with IFRIC 19 Extinguishing Financial Liabilities with Equity Instruments, the 708,999,985 ordinary shares were recognised at their fair value of 5 pence per share, a total of US$56.7 million, split between share capital and share premium (see notes 17 and 18). The PIK notes and promissory notes were recognised as liabilities at their respective fair values of US$26.7 million and US$3.4 million. As a result of the extinguishment, the previous carrying value of the Bonds of US$87.7 million was derecognised. The difference between the aggregate fair value of the new debt and equity issued of US$86.8 million and the US$87.7 million carrying value extinguished was US$0.9 million and was recognised as a gain on derecognition in the income statement during the year ended 31 March 2013 within finance income (note 7).

Movements in the Bonds during the year ended 31 March 2013 were as follows:

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

The PIK notes were recognised as a financial liability in their entirety, as the mandatory conversion to ordinary shares was contingent upon obtaining the requisite Kazakhstan regulatory approvals and thus outside the control of both the issuer and the holder. Subsequent to initial recognition at fair value, the PIK notes were carried at amortised cost whereby the carrying value increased at an effective interest rate of 10% until they were converted.

The movements in the PIK notes were as follows:

Interest expense

During the year ended 31 March 2014, the Group incurred US$10.3 million (2013: US$12.1 million) in interest expense in respect of its borrowings, of which US$6.0 million (2013: US$7.1 million) was capitalised to intangible assets - exploration and appraisal expenditure.

14. Deferred income tax

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

Deferred tax assets and liabilities are offset where the Group has a legally enforceable right to do so and are presented in the balance sheet after offset as follows:

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 Group did not recognise other potential deferred tax assets arising from losses of US$26.4 million (2013: US$23.2 million) as there is insufficient evidence of future taxable profits. Unrecognised losses of US$5.6 million can be carried forward up to ten years and the balance of losses of US$20.8 million can be carried forward indefinitely.

At 31 March 2014, the Group had other deferred tax assets of US$0.6 million (2013: US$nil) in respect of the exploration assets pool, depreciation and other temporary differences which had not been recognised because of insufficient evidence of future taxable profits.

There are no significant unrecognised temporary differences associated with undistributed profits of subsidiaries at 31 March 2014 and 2013, respectively.

15. Provision for liabilities and other charges

Analysis of total provisions:

Decommissioning

The decommissioning provision relates to non-producing oil and gas wells in the licence area at the time it was acquired and the wells drilled and facilities constructed by the Group since acquisition. The decommissioning provision reflects the present value of internal estimates of future decommissioning costs of the Group's oil and gas properties, as at the relevant balance sheet date, determined using local pricing conditions and requirements. The provision is estimated after taking account of inflation, years to abandonment and an appropriate discount rate. The decommissioning costs are expected to be incurred between 2017 and 2034.

The inflation rate used at 31 March 2014 to estimate the future expenditure was 6.7% (31 March 2013: 5.6%) and the discount rate used to determine the present value of the obligation was 7.6% (31 March 2013: 7.2%).

The actual decommissioning costs will ultimately depend on future market prices for the decommissioning work required, which will reflect market conditions at the relevant time. Furthermore, the timing of decommissioning is likely to depend on when the fields cease to produce at economically viable rates. This in turn will depend on future oil and gas prices, which are inherently uncertain.

Restructuring costs

The Group has established a restructuring provision of US$3.8 million as at 31 March 2014, for severance and other transitional expenses associated with various cost reduction measures. These include the closure of the Group's Houston office, the reduction in size and cost of the Group's London office, and a reduction in senior management and administrative personnel in Houston, London and in Kazakhstan.

16. Trade and other payables

The Group's accruals and deferred income includes US$19.7 million of prepayments from customers for crude oil sales (2013: US$19.2 million).

17. 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 2014, the Company issued 357,571,134 ordinary shares as a result of the mandatory conversion of US$28.6 million of PIK notes and accrued interest into shares at a price of 5p per share (note 13).

During the year ended 31 March 2013, the Company issued 799,245,491 ordinary shares, comprising:

·      708,999,985 new ordinary shares issued pursuant to the Bond Restructuring (note 13) upon the conversion of US$56.7 million of Bonds and accrued interest into shares.

·      90,245,506 new ordinary shares issued to Zhanros Drilling LLP ("Zhanros") in settlement of US$7.0 million of drilling and ancillary services (see below).

All shares issued are fully paid up.

Zhanros equity for services

On 8 August 2012, Max Petroleum 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 5p per share in lieu of cash payment.

During the year ended 31 March 2013, the Group received US$7.0 million of services under the Zhanros Agreement, all of which were fully settled by the issue of 90,245,506 ordinary shares during the reporting period.

Authorised share capital

On 13 October 2009 a special resolution was passed to replace the Company's Articles of Association. Under the new Articles of Association, effective 1 October 2009, the Company no longer has an authorised share capital and thus no longer has a statutory restriction on the maximum allotment of shares.

18. Share premium

19. Other reserves

Macquarie syndicate warrants

A restructuring of the Macquarie Facility in 2009 and subsequent increases in its borrowing base commitment vested warrants to subscribe for up to 365,278,737 ordinary shares of the Company at exercise prices between 4.54p and 5.67p (the "Warrant Deeds").

Exercise and expiry date

Each warrant tranche has an expiration date of five years from the date the relevant tranche vests, by which time the warrant holders need to have exercised their entitlement to subscribe for ordinary shares. 

Anti-dilution provisions

To prevent the dilution of the rights granted under the Warrant Deeds, the exercise price and the number of ordinary shares that may be purchased pursuant to the Warrant Deeds are subject to adjustments from time to time if ordinary shares are issued due to the conversion of the Company's Bonds or due to the exercise of employee share options issued on or before 30 June 2009.

The conversion of the PIK notes in September 2013 into 357,571,134 ordinary shares and the earlier conversion of the Bonds into 708,999,985 ordinary shares in December 2012 (see note 13) triggered the anti-dilution provisions under the Warrant Deeds. As a result, the warrant holders were issued additional warrants granting them a right to subscribe for 48,931,130 ordinary shares at 5p per share and the expiry date of the Warrant Deeds was set at 31 December 2015.

The table below sets out the warrants held by the Macquarie Facility syndicate partners at 31 March 2014 and 2013:

Of the outstanding Macquarie syndicate warrants at 31 March 2014, all 97,624,047 were fully vested and exercisable (2013: 48,692,917).

Convertible bond warrants

On 8 March 2009, 8 September 2009 and 8 September 2010, the Company elected to defer the cash interest payments due on its Bonds into additional principal, which each vested a five-year warrant exercisable at 5p per ordinary share over 30 million ordinary shares (the "Bondholder warrants").

The warrant table below sets out the Bondholder warrants outstanding at 31 March 2014 and 2013:

Of the outstanding Bondholder warrants at 31 March 2014, all 8,340,000 were fully vested and exercisable (2013: 8,340,000), of which 4,940,000 warrants expire on 8 September 2014 and 3,400,000 expire on 8 September 2015.

20. Notes to the cash flow statement

Reconciliation to cash generated from/(used in) operations

Summary of significant non-cash transactions

* Includes share-based payment arrangements with Zhanros (see note 17)

21. 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 Ministry of Oil and Gas of the Republic of Kazakhstan (the "MOG") and covers exploration and production activities in Blocks A&E from 2014 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. The Group expects that the future revenues generated from operating its fields will significantly exceed its obligations under the minimum work programme.

The total commitment at 31 March 2014 includes US$24.2 million 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 (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. 

22. Post balance sheet events

Strategic partner investment by AGR Energy

On 4 August 2014, the Group announced that it had agreed a conditional cash subscription with AGR Energy No. 1 Limited ("AGR Energy") which would raise approximately US$62.5 million before expenses as consideration for the issue for 2,264,093,462 new ordinary shares at a price of 1.64p per share (the "Subscription"). Immediately following completion of the Subscription, AGR Energy would hold 51% of the Company's enlarged issued share capital. AGR Energy is a vehicle owned by the Assaubayev family established for the purpose of the Subscription. The Subscription is conditional upon a number of conditions, including approval of the Company ' s shareholders and receiving regulatory approvals from the Government in Kazakhstan.

The Subscription would enable the Group to fund its planned capital programme to develop its post-salt fields and maximise reserves and production. In addition, Max Petroleum would be in a strengthened position to attract financial or industry partners to help finish its pre-salt NUR-1 well and to secure an extension of the exploration period of its Blocks A&E Licence in western Kazakhstan to enable it to have time to finish drilling NUR-1 and, if it is successful, the Kurzhem well. The Company would also be able to consider investment in other projects in Kazakhstan and across Central Asia that complement its existing activities.

Issuance of share options

On 27 May 2014 additional options to subscribe for 89 million new ordinary shares of the Company were granted to the Directors, officers and certain employees of the Company at an exercise price of 1.2p per share, of which one third are exercisable in equal amounts on the first, second and third anniversaries of the date of grant. The options have a term of four years and any unexercised options will expire on 27 May 2018.

Sberbank Loan

Subsequent to 31 March 2014, the Group repaid US$2.0 million of the Sberbank Loan (note 13), resulting in a total gross principal outstanding of US$85.9 million as at 19 August 2014.

23. Non-IFRS measures

The Group presents "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 profit/(loss) before finance income, finance expense, income tax expense, depreciation, depletion and amortisation, share-based payment expense, exploration and appraisal costs, restructuring 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: