Financial Results

RNS Number : 7661Z

Indus Gas Limited

22 September 2015

22^nd September 2015

Indus Gas Limited

('Indus' or 'the Company')

Preliminary Financial Results

Indus Gas Limited (AIM:INDI.L), an oil and gas exploration and development company with assets in India, is pleased to report its full year results for the 12 months to 31 March 2015.

Highlights

Operations:

§ Completed full year of production at enhanced capacity of 42 mmcf/d (33.5 mmcf/d net of CO₂) from SGL Field. Company is on track to increase gas production further in years ahead.

§ Approval of Declaration of Commerciality ("DOC") during the year for a ~2000 km² non SGL area to be retained as potential mining lease area (in addition to 176 km² of SGL Mining lease). An integrated Field Development Plan for this Non SGL Area is currently under preparation for submission on or before February 2016. The remaining Block area stands relinquished in line with PSC requirements.

§ Published new Competent Persons Report ("CPR") delivering a significant uplift in the Company's reserves (Gross 2P/2C of 4,091 Bcf in 2014 vs Gross 2P/2C of 3,272 Bcf in 2012). This is the Company's fourth CPR which has sequentially increased the hydrocarbon potential of the Block.

§ Successfully drilled a large number of appraisal wells with encouraging gas shows, which will help the Company put together a robust integrated field development plan for the Block area outside of SGL.

§ A new gas sand system (called P9) was successfully tested for production for the first time below producing zone P10 in Pariwar formation in SGL Field.

§ Ongoing discussions with counterparties to establish connection to cross country pipeline to Western states of Gujarat and North-West Pipeline Grid to enable long term gas monetisation.

Financial:

§ Invoiced revenues increased 49% to US$ 41.39m

§ Reported operating profit up 44% to US$ 30.02m

§ Reported profit after tax up 38% to US$ 16.24m

§ Concluded and drew down on new US$ 180m facility

§ Widened funding options with new Medium Term Note (MTN) programme

Mr Peter Cockburn, Chairman of the Company commented:

"This has been an extremely challenging period for the global oil and gas sector. Whilst the Indus Gas share price has not escaped the industry wide malaise, the Company's fundamentals have remained robust and several key milestones have been achieved during the financial year under review.

The Company's operational and financial performance has been strong with consistent revenues and profits generated during the period. The Company has also successfully secured additional balance sheet capacity, on very attractive terms, from which to fund future production growth and infrastructure investment.

The approval of the Declaration of Commerciality, granted in September 2014, marked the culmination of over a decade of intensive exploration and planning work on the block. It paves the way for the integrated development of our already significant, and growing, reserves base.

In 2014, Indus released its fourth Competent Person's Report. This delivered a 52% uplift in the Company's gross 2P reserves and an 11% increase in the 2C contingent resources base compared with the last CPR which was published in 2012. These impressive growth rates highlight the continued successful execution of the Company's appraisal and drilling programme."

In accordance with AIM rules, Paul Fink, Technical Consultant, a Geophysicist who holds an engineering degree from the Mining University of Leoben, Austria and has 25 years of industry experience is the qualified person that has reviewed the technical information contained in this release.

-ENDS-

For further information please contact:

Indus Gas Limited

Peter Cockburn

John Scott

+44(0)20 7614 5900

Arden Partners plc

Steve Douglas

Patrick Caulfield

+44(0)20 7614 5900

Bell Pottinger PR

Lorna Cobbett

+44(0)20 3772 2500

Introduction

Since flotation in June 2008 the Company has executed a clear and consistent strategy with the central objective being to maximise long term shareholder value creation from our licence block in North West India. This strategy has delivered prolific exploration success as evidenced by the rapid growth in our underlying reserves base and the successful execution of the first production phase.

Exploration and appraisal activity has continued at a rapid pace in the last twelve months with nine drilling rigs and over two thousand workers operating on site. This drilling and appraisal programme has delivered both a series of material new gas discoveries and provided further valuable insight into the gas structures present in the western half of our block.

The Company has also continued to invest heavily in the construction and development of our on-site infrastructure. The infrastructure is now in place to accommodate both the second and third phases of production scheduled to come on stream over the next two years and significantly, also provides some additional capacity from which to negotiate new supply contracts.

Domestic energy security remains one of the key challenges facing the government. India continues to be a major net importer of energy. This energy deficit can only be addressed through major investment programmes in long term infrastructure build and incentivising domestic energy companies to increase exploration and production.

Activity

Indus is pleased to announce another year of gas sales based on gas production capacity of 42 mmscfd (33.5 mmscfd net of CO₂) achieving consolidated adjusted revenues (including "ToP" receipts) of US$ 42.34 mn. We have continued to build scale in our production profile and our stated long term business plan remains on track. We continue to achieve this while maintaining compliance with the terms of our Production Sharing Contract, applicable laws and sound standards of health and safety. The approval of the DOC has opened the way to the establishment of an integrated Field Development Plan for the non SGL area of the Block. Our new CPR demonstrated our ability to convert resources into reserves and enhance the future revenues of the Block. We have also continued with our appraisal program and have completed significant drilling and testing, confirming and establishing further gas presence.

Declaration of Commerciality (DOC)

The DOC for a circa 2000 km² non SGL area of the Block (DOC Area) was approved by the Director-General Hydrocarbons (DGH) on the 18^th September 2014 and by the full Block Management Committee on the 20th October 2014. The DOC is another important step in the history of the Block as it recognises the commercial feasibility of the development of a large acreage in the Block. The DOC area along with the 176km² SGL Development Area are our chosen areas for future development work with the balance of block being relinquished.

The DOC has allowed work to begin on a Field Development Plan (FDP) for the area and this is expected to be completed under the usual process on or before February 2016 as required under the PSC. Approval of the FDP will pave the way for the grant of mining lease over the DOC area.

Competent Persons Report (CPR)

In December 2014 we announced the results of our latest CPR from Senergy Oil & Gas. The significant uplift in the Company's reserves and growth in Contingent Resources (shown below) reflects the major operational progress made on Block RJ-ON/6 since the last CPR was conducted in 2012. This is the third CPR completed by Senergy with substantially the same team members thereby building a continuity of analysis.

CPR Highlights:

· Gross 'Proven plus Probable' remaining reserves increased to 872 Bcf (Net of 18 bcf already produced as of 30 September 2014)

o 52% increase from 573 bcf assigned in previous CPR by Senergy in 2012

o Proven reserves increased to 423 Bcf as against 118 bcf assigned in previous CPR by Senergy in 2012

o New reserves largely attributed to new sands (lower P10) within SGL field and SSM fields

o Discounted cash flows at 10% IRR (NPV10) in respect of "Proven plus Probable" reserves of 872 Bcf estimated to be US$ 2,309mn (before capital expenses) and US$ 1,785mn (Net of capital expenses).

· 2C gross contingent resources increased 19% from 2,699 Bcf to 3,219 Bcf - Current CPR utilizes only some of the recent data used in the approval of the Declaration of Commerciality in respect of contingent resources.

· Best estimate prospective resources of over 2 TCF attributable to the wells outside the SGL development area

· Pipeline connection to existing cross country pipeline and western gas grids emerging as a viable option for long term gas monetization.

Summary table:

The table below provides a summary of the changes in reserves and resources from the report provided by Senergy in 2012 to the current updated report by Senergy:

	Senergy 2014 ^{see note 1}		Senergy 2012
Category	Gross (Bcf)	Net to Indus (Bcf)	Gross (Bcf)	Net to Indus (Bcf)
2P Reserves	872	672	573	449
2C Contingent Resources	3,219	2,897	2,699	2,429
Best Estimates Prospective Resource	2,004	1,804	2,182	1,964

Note 1: Senergy current reported numbers are net of 18 Bcf of gas already produced as of 30 September 2014

The table below provides a summary of current updated report by Senergy broken into different classifications for Gross Volumes:

Total Gas Volumes as per Senergy Report 2014 (Bcf)
Classification	1P	2P	3P
Reserves*	423	872	1,643
Classification	1C	2C	3C
Contingent Resources	991	3,219	6,698
Classification	Low Estimates	Best Estimates	High Estimates
Prospective Resource (Unrisked)	542	2,004	4,562

Note 1: Senergy current reported numbers are net of 18 Bcf of gas already produced as of 30 September 2014

This report has been completed in accordance with the 2007 Petroleum Resources Management System prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE). Details of the 2007 Petroleum Resources Management System together with definitions and glossary can be found at:

http://www.spe.org/industry/docs/Petroleum_Resources_Management_System_2007.pdf

The Company has continued drilling a number of appraisal and development wells during the year. A summary of cumulative seismic/drilling as at 31^st March 2015 is as follows:

§ 2019.05 Square km of 3D seismic data. This includes 106 square km of High Density 3D seismic acquired in SGL Field.

§ 1037.28 line km of 2D seismic data.

§ 15 wells drilled averaging 3,100 meters per well.

A summary of activities since April 2014 is provided below:

SGL Field Development

During the year, a total quantity of 12,902 mmscf of gas (2014: 8,085 mmscf) was produced from the field out of which 9,781 mmscf (net of CO2) was supplied to GAIL, which is a significant increase over the 6,691 mmscf supplied to them in the previous financial year. The operations at Rajasthan Rajya Vidyut Utpadan Nigam Limited (RRVUNL), the State Electricity Company in Rajasthan, have improved during the year resulting in increased gas off take in the second half of the year. The operations have now largely stabilized and GAIL expects to reach the gas off-take target as per signed GSPA on a long term basis, without needing to make "Take or Pay" payments. There were no major breakdowns during the year and GAIL met its obligations under the 'Take or Pay (ToP)' agreement. Invoiced revenues increased by 49% from the previous year as the power plant progressed towards normalized operations. The contribution under the "ToP" obligation was for US $ 0.95 mn, a significant decrease over the previous year due to the enhanced installed sales capacity of 33.5 mmscf/d being available for the full financial year.

Activities to support additional sales to GAIL have made good progress. Additional successful production wells have been completed and tied into the gas gathering system. Treatment and processing plants are in place.

Drilling, Seismic, Completion Operations

Operational activities over the last year have largely followed the Group's various objectives:

a) appraisal drilling to support the DOC application and integrated field development plans;

b) drilling and completion of production wells for the SGL Field Development continued as planned to meet contracted and planned gas sale requirements;

c) testing various wells previously drilled, where gas shows were encountered to enable the Group to increase its reserve base; and

d) testing the tight gas recovery potential in addition to conventional gas discovered in the Pariwar formation.

During the year, Indus has been acquiring, in phases, new seismic data giving more clarity on the Block potential and providing additional drilling prospects. The current drilling programme is progressing on schedule and producing positive results. We continue to test concepts and obtain log and core data for analysis outside the SGL area. In the SGL area work continues to expand the knowledge of the producing intervals. Additional testing is part of a programme to enhance production and maximize recovery of gas through good asset management. Activities such as this will increase as we obtain and act on new data and production history. An important development in respect of SGL Field was discovery of a new sand system called P9 or lower P10 sands, located just below the existing producing upper P10 sands in Pariwar formation. This new sand system was successfully tested for production and going forward will likely add to the reserves and production from existing as well as new wells.

The details of the wells, which were drilled during the year, are as follows:

Development wells

Development/production wells drilled during the year included the following:

SGL-SB1 - 3277m Gas Producer (Pariwar Formation)

The SGL-SB1 well was drilled to the base of the Pariwar P10 reservoir zone at 3277m on the southern flank of the main SGL Field structural closure area. The well was completed with a barefoot completion with an open hole interval of 207 metres (from 3070-3277m) covering the entire P10 and P20 Pariwar Reservoir Zones and is currently on production. Initial pressure transient and deliverability tests achieved flow rates of 1.03 mmscf/d on a 6mm choke to 5.07 mmscf/d on a 10mm choke for this well.

SGL-15 - 3286m Gas Producer (Pariwar Formation)

Well SGL-15 terminated at 3286 metres within the Pariwar Formation to allow full evaluation of the P10 and P20 Reservoir zones. The well is situated to the east of the main SGL Field structural closure area within the same fault compartment previously targeted by wells SSF-3 and SGL-P2. The well is currently perforated and completed for production from the P20 reservoir zone over the interval 3023-3032m with flow rates ranging from 1.87 mmscf/d on an 8mm choke to 2.06 mmscf/d on a 12mm choke achieved during pressure transient and deliverability testing.

SGL-16 (SGL SB-2) - 3196m Gas Producer (Pariwar Formation)

Well SGL-16 reached a total depth of 3196m which corresponded to the base of the Pariwar P10 Reservoir Zone. It is located within a crestal position within the main SGL Field structural closure area. The well was cased with the interval 3111-3117m (Uppermost P10 Zone) perforated and completed for production with a flow rate of 4.48 mmscf/d recorded on an 8mm choke (and 6.51 mmscf/d on a 10mm choke) during pressure transient and deliverability testing.

SGL-SB3- 3344m Gas Producer (Pariwar Formation)

Well SGL-SB3 was drilled as an SGL field development well within a discrete fault compartment on the western flank of the SGL Field structure, which had previously also been targeted by well SGL-D2. The SGL-SB3 well encountered key gas shows within sands in the upper part of the Pariwar P10 reservoir zone, which correlated directly with sands that were currently on production in the other nearby SGL Field wells. Crucially, SGL-SB3 also encountered gas-bearing sands in the lower part of the P10 reservoir zone interval that were not on production in any other well at that time in the SGL Field area. The well was cased and completed for production from a 10 metre perforation zone from the lower P10 reservoir sands (3282-3292m measured depth). This interval is currently on production from this new additional producing zone discovered in the well. Additional gas-bearing upper P10 sands are currently behind casing with future additional development potential.

SGL-18 - 3325m Gas Producer (Pariwar Formation)

The SGL-18 SGL Field development well was drilled on the western flank of the same structural fault compartment as the previous SGL-SB3 well. It was drilled in a down-dip position on the structure relative to SGL-SB3 in order to test the extent of the lower P10 gas bearing sands as encountered in that well. The SGL-18 well encountered key gas shows in the upper parts of the P10 reservoir zone. It also encountered key gas sands in the lower P10 zone as seen in SGL-SB3. The well was cased and completed for production from a 12 metre perforation within the lower P10 reservoir zone sand interval from 3258-3270m (measured depth), with the upper P10 zone gas sands currently behind casing allowing future additional development potential. The well is currently on production from the lower P10 sand zone.

SGL-19 - 3299m Gas Producer (Pariwar Formation)

Well SGL-19 was drilled as an infill SGL Field development well on the main SGL Field structural compartment which was previously drilled by nearby wells SGL-1, SGL-6 and SGL-7. Production taken to date from this structural compartment had been from the upper P10 zone reservoir sands only at the time of drilling. The SGL-19 well encountered key gas shows in both the upper and lower P10 reservoir sand zones and was subsequently cased and completed for production from a 9 metre zone (3243.5-3252.5m measured depth) in the lower P10 target sands. The well was placed on production from the lower P10 sands from the same zone as wells SGL-SB3 and SGL-18. Additional upper P10 reservoir sands are currently behind casing with potential for future additional development.

SGL-20 - 3411m Development well (Pariwar Formation)

The SGL-20 development well was drilled on the southern flank of the SGL Field in a down-dip location. The well encountered gas shows in the Pariwar P20 reservoir sands and within the upper part of the P10 Pariwar reservoir zone. The well has been cased but has not been completed for production to-date.

SGL-21 - 3357.6m Gas Producer (Pariwar Formation)

Well SGL-21 was drilled as a development well on the northern flank of the main SGL Field structural closure area. The well encountered key gas shows within the upper P10 Pariwar reservoir zone. It was cased and completed for production from a 3 metre perforation (3208-3211m measured depth) from the uppermost sands of the P10 reservoir zone. The well is currently on production from this zone.

SGL-23 - 3409m Gas Producer (Pariwar Formation)

The SGL-23 development well is located on the crestal part of the western SGL Field structural closure area that was also drilled by SGL-SB3 and SGL-18. The well encountered key gas shows in the upper and lower target intervals of the Pariwar P10 reservoir zone. It was cased and completed for production from a 12 metre perforation zone (3318-3330m measured depth) from key lower P10 zone reservoir sands. The well is currently on production (since March 2015).

SGL-28 - 3270m Development well (Pariwar Formation)

The SGL-28 development well is located close to the crestal part of the western SGL Field structural closure area that was also drilled by SGL-SB3, SGL-18 and SGL-23. The well encountered key gas shows in the upper and lower target intervals of the Pariwar P10 reservoir zone. It was cased and completed for production testing from a 12 metre perforation zone (3250-3262m measured depth) from key lower P10 zone reservoir sands. The well is currently undergoing testing and preparation to be placed on production at the time of writing.

Appraisal Wells

During the year, the Company has completed the following appraisal wells and has encountered gas shows in the majority of these wells. Most of these wells are in testing stages and are critical in establishing our right to retain the maximum area in the Block in line with the DOC application and establishing additional reserves and resources. Since many of these wells have multi-zone gas shows, the Company is evaluating an optimum strategy for multi-zone testing and completion (having previously gathered favourable data sufficient for the DOC application).

Description of some of the appraisal wells completed in the year is as follows:

A-11-7N - 3378.3m Appraisal well with gas shows (Pariwar Formation)

Well A-11-7N was drilled in order to appraise the same structural closure area as older well SSM-1, which encountered gas shows at the Pariwar reservoir levels but had to be abandoned prior to wireline logging and testing due to hole complications. A-11-7N encountered gas shows within Pariwar P20 and P10 zone sands at multiple levels. The well was cased and one zone selected for testing from the main P10 (upper) reservoir zone from a 4.5 metre perforation interval (3224-3228.5m). To-date this zone has failed to flow gas to surface at commercial rates and the well is suspended pending further review.

S-EPN-1 - 3489m Appraisal well with minor gas shows (Pariwar Formation)

Well S-EPN-1 was drilled in very close proximity to a major fault trend with the aim to assess whether natural fractures associated with faulting would enhance reservoir productivity. The well terminated within the upper parts of the Pariwar P10 reservoir zone and only minor elevated gas readings were observed whilst drilling. The well was subsequently abandoned and no further testing was carried out at this location.

SX-7 - 4581m Appraisal well with gas (Pariwar and B&B Formations)

Well SX-7 targeted a discrete fault compartment in the western area of RJ-ON/6 for appraisal of Pariwar and B&B Formation reservoir targets in this area. The well encountered elevated gas shows within the Pariwar P20 and P10 reservoir zones and drilled on to the deeper B&B Formation targets. Gas shows were then encountered in upper B&B Formation target sands, with major shows encountered whilst drilling the main Lower B&B target zone. Core was taken from key reservoir target zones and the well is currently undergoing detailed petrophysical, geological and geomechanical analysis in order to assess how best to proceed with further testing of the key gas-bearing reservoir targets encountered in this well.

S-97S - 132m Appraisal well with gas (Pariwar and B&B Formations)

The aim of the S-97S Appraisal well was to assess a major structural closure in the western part of RJ-ON/6 which had been previously drilled by well S-97. The S-97S well encountered significant gas shows in the Pariwar P20 and P10 reservoir zones and within target sands within the upper parts of the B&B Formation. The Lower B&B sands were not penetrated by this well. The well was cased and 4 upper B&B sand zones were selected for initial perforation and testing, covering the intervals 3937-3940m, 3948-3951m, 3958-3961m and 3980-3989m. Testing and assessment of this well is ongoing at the time of writing.

EPN-2 - 1651m Gas Producer (Pariwar Formation)

Well EPN-2 was drilled in order to appraise the structural closure area in the western part of RJ-ON/6 previously successfully tested for gas (from the Pariwar Formation) by well EPN-1. Furthermore, B&B Formation reservoir zones were also targeted by EPN-2 which were not penetrated by EPN-1. The well encountered key gas shows in the Pariwar P20 and P10 reservoir zones and within upper and lower B&B target zones. Cores were taken from key reservoir intervals and (at the time of writing) the well is currently undergoing detailed petrophysical, geological and geomechanical analysis in order to assess how best to proceed with further testing of the key gas-bearing reservoir targets encountered in this well.

Seismic

We have 3D seismic coverage of 2019.05 square km area as of 31 March 2015. This includes 106 square km of high density 3D seismic acquired in SGL Field area. We have 89% of 3D Seismic coverage of the 2,000 Square km DOC area and currently work is ongoing to complete the seismic data set to cover the entire 2000 km2 DOC area.

Financials

During the financial year, the Company supplied 9,781 mmscf of gas and invoiced revenues of US$ 41.39 mn (2013/14 US$ 27.83 mn), resulting in reported operating profit of US$ 30.02 mn (2013/14 US$ 20.93 mn). The reported profit after tax was US$ 16.24 mn (2013/14 US$ 11.77 mn) after a foreign exchange loss of US$ 0.02 mn. Indus additionally received take or pay payments of US$ 0.95 mn for the period, which is considered as deferred revenues and shown as liabilities since these receipts can potentially be set off against future gas supplies to GAIL, provided such supplies are over and above 90% of the contracted quantities, subject to certain restrictions as to the period in which such offset can be made. An amount of US$ 5.08 mn is disclosed as current liabilities and the remaining US$ 25.56 mn is disclosed as non-current liabilities. Current liabilities include the maximum amount for which the Company is obliged to supply gas against the "ToP" amount received, in the next twelve months. Further the Company is not obliged to supply the gas over and above 100% of the contracted quantities in any given period. In the event, the set-off terms are not complied with, the Company has no further obligation to return back "ToP" amounts. Since the amount of "ToP" invoiced is non-refundable, the management considers this amount as a revenue and profit adjustment and accordingly adjusted consolidated revenues, operating profit and profit before tax for the year were respectively US$ 42.34 mn, US$ 30.97 mn and US$ 30.95 mn after including "ToP" amount of US$ 0.95 mn.

While the Company is not expected to pay any significant taxes on its income for many years in view of the 100% deduction allowed under Indian Income Tax Act on the capital expenses in the Block, the Company has accrued a non-cash deferred tax liability of US$ 13.76 mn as per IFRS requirements.

Post this deferred tax liability provision, the net profit for the year was US$ 16.24 mn.

The expenditure on exploration and evaluation assets during the year was US$ 34.02 mn. In addition during the year subsequent to the discovery of gas reported to regulatory authorities, an amount of US$ 34.02 mn has been transferred from exploration and appraisal assets to development assets. The value of development assets and other tangible plant and machinery has increased to US$ 491.34 mn. The development assets amortised on the gas produced during the year was US$ 7.58 mn.

The current assets (excluding cash) as of 31 March 2015 stood at US$ 11.88mn, which includes US$ 5.23 mn of inventory and US$ 5.33 mn of trade receivables. The trade receivables are mainly on account of fortnightly receivables from GAIL billed on the last day of the year. The current liabilities of the Company, excluding the related party liability of US$ 23.49 mn and current portion of long term debt of US$ 18.39 mn, stood at US$ 5.24 mn. This comprised mainly of deferred revenue of US$ 5.08 mn and other liabilities of US$ 0.2 mn.

As of 31 March 2015, the outstanding term loan of the Company was US$ 218.68 mm, out of which US$ 18.39 mn was categorised as repayable within a year and the remaining US$ 200.29 mn has been categorised as a long term liability. During the year, the Company has received proceeds of US$ 131.50 mn from incremental term loan facility net of expenses and repaid an amount of US$ 17.32 mm of the outstanding term loan facilities, as per the scheduled repayment plan.

Outlook

During the next twelve months, we expect a further step change in the growth of the Company. Following DOC approval we shall look to develop the significant potential of the Block beyond our existing SGL Development Area. Strong progress has been made on the preparation of additional gas gathering and processing facilities. A cumulative gas processing capacity of 130 mmscf/d is being planned to be available by end 2016 to provide a strong platform from which to negotiate further new gas supply contracts. We look forward to continued drilling success in both Pariwar and B&B. Negotiations on the new gas sales contract with GAIL for off-take by the power plant in January 2017 are ongoing. The Company is also progressing the dialogue for the review of gas pricing under our existing sales contract.

Indus Gas Limited and its subsidiaries

31 March 2015

Independent Auditor's Report to the Members of Indus Gas Limited

We have audited the consolidated financial statements of Indus Gas Limited (the 'Company') for the ended 31 March 2015 which comprise the Consolidated Statement of Financial Position, the Consolidated Statement of Comprehensive Income, the Consolidated Statement of Changes in Equity, the Consolidated Statement of Cash Flow and the related notes. The financial reporting framework that has been applied in their preparation is applicable law and International Financial Reporting Standards (IFRSs) as adopted by the European Union (EU).

This report is made solely to the company's members, as a body, in accordance with Section 262 of The Companies (Guernsey) Law, 2008. Our audit work has been undertaken so that we might state to the company's members those matters we are required to state to them in an auditors' report and for no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility to anyone other than the company and the company's members as a body, for our audit work, for this report, or for the opinions we have formed.

Respective responsibilities of directors and auditors

As explained more fully in the Statement of Directors' Responsibilities on pages 13 and 14 the directors are responsible for the preparation of the consolidated financial statements which give a true and fair view.

Our responsibility is to audit and express an opinion on the consolidated financial statements in accordance with applicable Law and International Standards on Auditing (UK and Ireland). Those standards require us to comply with the Auditing Practices Board's Ethical Standards for Auditors.

Scope of the audit of the consolidated financial statements

An audit involves obtaining evidence about the amounts and disclosures in the consolidated financial statements sufficient to give reasonable assurance that the consolidated financial statements are free from material misstatement, whether caused by fraud or error. This includes an assessment of whether the accounting policies are appropriate to the Group's circumstances and have been consistently applied and adequately disclosed; the reasonableness of significant accounting estimates made by the directors; and the overall presentation of the consolidated financial statements. In addition, we read all the financial and non-financial information in the annual report to identify material inconsistencies with the audited financial statements and to identify any information that is apparently materially incorrect based on, or materially inconsistent with, the knowledge acquired by us in the course of performing the audit. If we become aware of any apparent material misstatements or inconsistencies we consider the implications for our report.

Opinion on the consolidated financial statements

In our opinion, the consolidated financial statements:

· give a true and fair view of the state of the Group's affairs as at 31 March 2015 and of its profit for the then ended;

· have been properly prepared in accordance with IFRSs as adopted by the EU; and

· comply with the requirements of The Companies (Guernsey) Law, 2008.

Matters on which we are required to report by exception

We have nothing to report in respect of the following:

Under The Companies (Guernsey) Law, 2008 we are required to report to you, if in our opinion:

· proper accounting records have not been kept by the Group; or

· the consolidated financial statements are not in agreement with the accounting records; or

· we have not obtained all the information and explanations, which to the best of our knowledge and belief, are necessary for the purposes of our audit.

Grant Thornton Limited

Chartered Accountants

St Peter Port, Guernsey, Channel Islands

21 September 2015

Consolidated Statement of Financial Position

(All amounts in United States Dollars, unless otherwise stated)

		Note	31 March 2015		31 March 2014 (Restated)
ASSETS
Non-current assets
Intangible assets: exploration and evaluation assets		6	-		-
Property, plant and equipment		7	483,794,473		408,582,251
Tax assets			1,228,787		726,511
Other assets			6,225		885
Total non-current assets			485,029,485		409,309,647
Current assets
Inventories		10	5,231,415		9,326,267
Trade receivables			5,330,484		7,847,404
Other current assets		11	1,317,697		408,645
Cash and cash equivalents		12	12,251,533		977,028
Total current assets			24,131,129		18,559,344
Total assets			509,160,614		427,868,991

LIABILITIES AND EQUITY
Shareholders' equity
Share capital		13	3,619,443		3,619,443
Additional paid-in capital		13	46,733,689		46,733,689
Currency translation reserve		13	(9,313,781)		(9,313,781)
Merger reserve		13	19,570,288		19,570,288
Share option reserve		20	324,865		324,865
Retained earnings			27,225,937		10,981,346
Total shareholders' equity			88,160,441		71,915,850

Liabilities
Non-current liabilities
Long term debt from banks, excluding current portion		14	200,293,945		85,266,117
Provision for decommissioning		15	1,281,862		1,079,946
Deferred tax liabilities (net) Payable to related parties, excluding current portion		8 16	26,445,323 120,288,834		12,687,726 112,947,262
Deferred revenue			25,563,995		24,618,832
Total non-current liabilities			373,873,959		236,599,883
Current liabilities
Current portion of long term debt from banks	14			18,389,976		17,301,889
Current portion payable to related parties	16			23,490,343		96,847,805
Accrued expenses and other liabilities				168,809		126,478
Deferred revenue				5,077,086		5,077,086
Total current liabilities				47,126,214		119,353,258

Total liabilities				421,000,173		355,953,141

Total equity and liabilities				509,160,614		427,868,991

(The accompanying notes are an integral part of these consolidated financial statements)

These consolidated financial statements were approved and authorised for issue by the board on 21 September 2015 and was signed on its behalf by:

Peter Cockburn

Director

Consolidated Statement of Comprehensive Income

(All amounts in United States Dollars, unless otherwise stated)

	Note	Year ended 31 March 2015	Year ended 31 March 2014

Revenues		41,393,184	27,834,635
Cost of sales		(8,542,085)	(5,454,884)
Gross profit		32,851,099	22,379,751

Cost and expenses
Administrative expenses		(2,832,584)	(1,453,590)
Operating profit		30,018,515	20,926,161

Foreign currency exchange (loss)/ gain	18	(16,469)	78,889
Interest income		141	127
Profit before tax		30,002,187	21,005,177

Income taxes	9
- Deferred tax expense		(13,757,596)	(9,233,244)
Total comprehensive income for the year (attributable to the shareholders of the Group)		16,244,591	11,771,933

Earnings per share	21

Basic		0.09	0.06
Diluted		0.09	0.06

(The accompanying notes are an integral part of these consolidated financial statements)

Consolidated Statement of Changes in Equity

(All amounts in United States Dollars, unless otherwise stated)

	Common stock		Additional paid in capital	Currency translation reserve	Merger reserve	Share option reserve	Retained earnings/(accumulated losses)	Total shareholders' equity
	No. of shares	Amount	Additional paid in capital	Currency translation reserve	Merger reserve	Share option reserve	Retained earnings/(accumulated losses)	Total shareholders' equity
Balance as at 1 April 2013	182,973,924	3,619,443	46,733,689	(9,313,781)	19,570,288	324,865	(790,587)	60,143,917
Profit and total comprehensive income for the year	-	-	-	-	-	-	11,771,933	11,771,933
Balance as at 31 March 2014	182,973,924	3,619,443	46,733,689	(9,313,781)	19,570,288	324,865	10,981,346	71,915,850	-
Comprehensive income for the year	-	-	-	-	-	-	16,244,591	16,244,591
Balance as at 31 March 2015	182,973,924	3,619,443	46,733,689	(9,313,781)	19,570,288	324,865	27,225,937	88,160,441

(The accompanying notes are an integral part of these consolidated financial statements)

Consolidated Statement of Cash Flow

(All amounts in United States Dollars, unless otherwise stated)

	Note	Year ended 31 March 2015	Year ended 31 March 2014
Cash flow from operating activities
Profit before tax		30,002,187		21,005,177
Adjustments
Loan processing cost		(4,100,000)		-
Unrealised exchange (gain)/loss	18	16,469		(1,423)
Interest income		(141)		(127)
Depreciation	7	7,584,042		4,773,127
Changes in operating assets and liabilities
Inventories		4,094,852		(3,351,651)
Trade receivables		2,516,920		2,078,625
Other current and non-current assets		96,938		(365,518)
Deferred revenue		945,163		15,600,222
Payable to related party-operating activities		9,035,452		5,684,190
Accrued expenses and other liabilities		7,454		127,609
Cash generated from operations		50,199,337		45,550,231
Income taxes paid		(502,276)		(495,655)
Net cash generated from operating activities		49,697,061		45,054,576
Cash flow from investing activities
Purchase of property, plant and equipment ^A		(150,716,436)		(28,820,986)
Interest received		141		127
Net cash used in investing activities		(150,716,295)		(28,820,859)
Cash flow from financing activities Repayment of long term debt from banks		(17,320,000)		(17,320,000)
Proceeds from long term debt from banks		135,600,000		-
Payment of interest		(5,984,930)		(5,486,986)
Net cash generated from/(used in) financing activities		112,295,070		(22,806,986)
Net increase/(decrease) in cash and cash equivalents		11,275,835		(6,573,269)
Cash and cash equivalents at the beginning of the year		977,028		7,546,024
Effects of exchange differences on cash and cash equivalents		(1,330)		4,273
Cash and cash equivalents at the end of the year		12,251,533		977,028

^AThe purchase of property, plant and equipment above, includes additions to exploration and evaluation assets amounting to US$ 34,017,324 (previous year: US$ 59,380,804) transferred to development cost, as explained in Note 6.

(The accompanying notes are an integral part of these consolidated financial statements)

Notes to Consolidated Financial Statements

(All amounts in United States Dollars, unless otherwise stated)

1. INTRODUCTION

Indus Gas Limited ("Indus Gas" or "the Company") was incorporated in the Island of Guernsey on 4 March 2008 pursuant to an Act of the Royal Court of the Island of Guernsey. The Company was set up to act as the holding company of iServices Investments Limited. ("iServices") and Newbury Oil Co. Limited ("Newbury"). iServices and Newbury are companies incorporated in Mauritius and Cyprus, respectively. iServices was incorporated on 18 June 2003 and Newbury was incorporated on 17 February 2005. The Company was listed on the Alternative Investment Market (AIM) of the London Stock Exchange on 6 June 2008. Indus Gas through its wholly owned subsidiaries iServices and Newbury (hereinafter collectively referred to as "the Group") is engaged in the business of oil and gas exploration, development and production.

Focus Energy Limited ("Focus"), an entity incorporated in India, entered into a Production Sharing Contract ("PSC") with the Government of India ("GOI") and Oil and Natural Gas Corporation Limited ("ONGC") on 30 June 1998 for petroleum exploration and development concession in India known as RJ-ON/06 ("the Block"). Focus is the Operator of the Block. On 13 January 2006, iServices and Newbury entered into an interest sharing agreement with Focus and obtained a 65 per cent and 25 per cent share respectively in the Block. Consequent to this, the Group acquired an aggregate of 90 per cent participating interest in the Block and the balance 10 per cent of participating interest is owned by Focus. The participating interest explained above is subject to any option exercised by ONGC in respect of individual wells (already exercised for SGL field as further explained in Note 3).

2. GENERAL INFORMATION

The consolidated financial statements of the Group have been prepared in accordance with International Financial Reporting Standards ('IFRS') as adopted by the European Union ('EU'). The consolidated financial statements have been prepared on a going concern basis (refer to Note 27), and are presented in United States Dollar (US$). The functional currency of the Company as well as its subsidiaries is US$.

3. JOINTLY CONTROLLED ASSETS

The Group participates in an unincorporated joint arrangement with Focus wherein the Group's interest in this arrangement was classified as jointly controlled assets. Following implementation of IFRS 11: Joint Arrangements, the Group's interest in this arrangement is now classified as Joint operation. All rights and obligations in respect of exploration, development and production of oil and gas resources under the 'Interest sharing agreement' are shared between Focus, iServices and Newbury in the ratio of 10 per cent, 65 per cent and 25 per cent respectively.

Under the PSC, the GOI, through ONGC has an option to acquire a 30 per cent participating interest in any discovered field, upon such successful discovery of oil or gas reserves, which has been declared as commercially feasible to develop.

Subsequent to the declaration of commercial discovery in SGL field on 21 January 2008, ONGC had exercised the option to acquire a 30 per cent participating interest in the discovered fields on 6 June 2008. The exercise of this option would reduce the interest of the existing partners proportionately.

On exercise of this option, ONGC is liable to pay its share of 30 per cent of the SGL field development costs and production costs incurred after 21 January 2008 and are entitled to a 30 per cent share in the production of gas subject to recovery of Contract costs as explained below.

The allocation of the production from the field to each participant in any year is determined on the basis of the respective proportion of each participant's cumulative unrecovered contract costs as at the end of the previous year or where there are no unrecovered contract cost at the end of previous year on the basis of participating interest of each such participant in the field. For recovery of past contract cost, production from the field is first allocated towards exploration and evaluation cost and thereafter towards development cost.

On the basis of the above, gas production for the years ended 31 March 2015 and 2014 is shared between Focus, iServices and Newbury in the ratio of 10 per cent, 65 per cent and 25 per cent, respectively.

The aggregate amounts relating to jointly controlled assets, liabilities, expenses and commitments related thereto that have been included in the consolidated financial statements are as follows:

	31 March 2015	31 March 2014

Non-current assets	483,794,473	408,582,251
Current assets	5,231,415	9,326,267

Non-current liabilities	1,281,862	1,079,946
Current liabilities	23,490,343	96,847,805

Expenses (net of finance income)	9,035,452	5,684,190

Commitments	NIL	NIL

The GOI, through ONGC, has option to acquire similar participating interest in any future successful discovery of oil or gas reserves in the Block.

4. STANDARDS AND INTERPRETATIONS ISSUED BUT NOT EFFECTIVE AND YET TO BE APPLIED BY THE GROUP

Summarised in the paragraphs below are standards, interpretations or amendments that have been issued prior to the date of approval of these consolidated financial statements and endorsed by EU and will be applicable for transactions in the Group but are not yet effective. These have not been adopted early by the Group and accordingly, have not been considered in the preparation of the consolidated financial statements of the Group.

Management anticipates that all of these pronouncements will be adopted by the Group in the first accounting period beginning after the effective date of each of the pronouncements. Information on the new standards, interpretations and amendments that are expected to be relevant to the Group's consolidated financial statements is provided below.

· IFRS 9 Financial Instruments Classification and Measurement

In July 2014, the International Accounting Standards Board issued the ﬁnal version of IFRS 9, Financial Instruments. The standard reduces the complexity of the current rules on ﬁnancial instruments as mandated in IAS 39. IFRS 9 has fewer classiﬁcation and measurement categories as compared to IAS 39 and has eliminated the categories of held to maturity, available for sale and loans and receivables. Further it eliminates the rule-based requirement of segregating embedded derivatives and tainting rules pertaining to held to maturity investments. For an investment in an equity instrument which is not held for trading, IFRS 9 permits an irrevocable election, on initial recognition, on an individual share-by-share basis, to present all fair value changes from the investment in other comprehensive income. No amount recognized in other comprehensive income would ever be reclassiﬁed to proﬁt or loss. It requires the entity, which chooses to measure a liability at fair value, to present the portion of the fair value change attributable to the entity's own credit risk in other comprehensive income.

IFRS 9 replaces the 'incurred loss model' in IAS 39 with an 'expected credit loss' model. The measurement uses a dual measurement approach, under which the loss allowance is measured as either 12 month expected credit losses or lifetime expected credit losses. The standard also introduces new presentation and disclosure requirements.

This standard is effective for reporting periods beginning on or after 1 January 2018 with early adoption permitted. The management is currently evaluating the impact that this new standard will have on its consolidated financial statements.

· IFRS 15 Revenue from contracts with customers

The International Accounting Standards Board (IASB) has published a new standard, IFRS 15 Revenue from Contracts with customers. This standard replaces IAS 11 Construction Contracts, IAS 18 Revenue, IFRIC 13 Customer Loyalty Programmes, IFRIC 15 Agreements for the Construction of Real Estate, IFRIC 18 Transfers of Assets from Customers, and SIC-31 Revenue- Barter Transactions involving advertising services. It sets out the requirements for recognising revenue that apply to contracts with customers, except for those covered by standards on leases, insurance contracts and financial instruments.

The new standard establishes a control-based revenue recognition model and provides additional guidance in many areas not covered in detail under existing IFRSs, including how to account for arrangements with multiple performance obligations, variable pricing, customer refund rights, supplier repurchase options, and other common complexities.

This standard is effective for reporting periods beginning on or after 1 January 2017 with early adoption permitted. It applies to new contracts created on or after the effective date and to the existing contracts that are not yet complete as of the effective date.

The management is currently evaluating the impact that this new standard will have on its consolidated financial statements.

5. SUMMARY OF ACCOUNTING POLICIES

The consolidated financial statements have been prepared on a historical basis, except where specified below. A summary of the significant accounting policies applied in the preparation of the accompanying consolidated financial statements are detailed below:

5.1. BASIS OF CONSOLIDATION

The consolidated financial statements include the financial statements of the parent company and all of its subsidiary undertakings drawn up to 31 March 2015. The Group consolidates entities which it controls. Control exists when the parent has power over the entity, is exposed, or has rights, to variable returns from its involvement with the entity and has the ability to affect those returns by using its power over the entity. Power is demonstrated through existing rights that give the ability to direct relevant activities, those which significantly affect the entity's returns.

The Group recognises in relation to its interest in a joint operation:

a. its assets, including its share of any assets held jointly;

b. its liabilities, including its share of any liabilities incurred jointly;

c. its revenue from the sale of its share of the output arising from the joint operation;

d. its share of the revenue from the sale of the output by the joint operation; and

e. its expenses, including its share of any expenses incurred jointly.

Intra-Group balances and transactions, and any unrealised gains and losses arising from intra-Group transactions are eliminated in preparing the consolidated financial statements. Amounts reported in the financial statements of subsidiaries have been adjusted where necessary to ensure consistency with the accounting policies adopted by the Group.

Profit or losses of subsidiaries acquired or disposed of during the year are recognised from the date of control of acquisition, or up to the effective date of disposal, as applicable.

5.2. SIGNIFICANT ACCOUNTING JUDGEMENTS AND ESTIMATES

In preparing consolidated financial statements, the Group's management is required to make judgements, estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statement and the reported amounts of revenues and expenses during the reporting period. Although these estimates are based on management's best knowledge of current events and actions, actual results may ultimately differ from those estimates. The management's estimates for the useful life and residual value of tangible assets, impairment of tangible and intangible assets and recognition of provision for decommissioning represent certain particularly sensitive estimates. The estimates and underlying assumptions are reviewed on an on-going basis. Revisions to accounting estimates are recognised in the period in which the estimate is revised if the revision affects only that period or in the period of the revision and future periods if the revision affects both current and future periods. Information about significant judgements, estimates and assumptions that have the most significant effect on recognition and measurement of assets, liabilities, income and expenses is provided in Note 26.

5.3. FOREIGN CURRENCIES

The consolidated financial statements have been presented in US$.

Foreign currency transactions are translated into the functional currency of the respective Group entities, using the exchange rates prevailing at the dates of the transactions (spot exchange rate). Functional currency is the currency of the primary economic environment in which the entity operates.

Foreign exchange gains and losses resulting from the settlement of such transactions and from the re-measurement of monetary items at year-end exchange rates are recognised in the profit or loss for the year.

Non-monetary items measured at historical cost are recorded in the functional currency of the entity using the exchange rates at the date of the transaction.

5.4. REVENUE RECOGNITION

Revenue from the sale of natural gas and condensate production (a by- product) is recognised when the significant risks and rewards of ownership have been transferred, which is when title passes to the customer. This occurs when product is physically transferred into a vessel, pipe or other delivery mechanism.

Revenue is stated after deducting sales taxes, excise duties and similar levies.

Per the 'Take-or-Pay' agreement, GAIL (India) Limited ('GAIL' or the 'customer') is committed towards taking a certain minimum quantity of gas and paying for any related shortfall. The Group's entitlement to receive revenue for any shortfall is recorded as trade receivables with a corresponding credit to deferred revenue. Until the expiry of the contracted period, the Group continues to have an obligation to deliver the deficit to GAIL. Revenue for the deficit quantity would be recognised at the earlier of delivery of physical quantity towards the deficit to GAIL or at the expiry of the contract period. Deferred revenue represents amounts received/due from GAIL for which gas is yet to be delivered.

5.5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment comprises of Development assets and other properties, plant and equipment used in the gas fields and for administrative purposes. These assets are stated at cost plus decommissioning cost less accumulated depreciation and any accumulated impairment losses.

Development assets are accumulated on a field by field basis and comprise of costs of developing the commercially feasible reserve, expenditure on the construction, installation or completion of infrastructure facilities such as platforms, pipelines and other costs of bringing such reserves into production. It also includes the exploration and evaluation costs incurred in discovering the commercially feasible reserve, which have been transferred from the exploration and evaluation assets as per the policy mentioned in note 5.6. As consistent with the full cost method, all exploration and evaluation expenditure incurred up to the date of the commercial discovery have been classified under development assets of that field.

The carrying values of property, plant and equipment are reviewed for impairment when events or changes in circumstances indicate that the carrying values may not be recoverable.

An item of property, plant and equipment is derecognised upon disposal or when no future economic benefits are expected from its use or disposal. Any gain or loss arising on de-recognition of the asset (calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is included in the profit or loss of the year in which the asset is derecognised. However, where the asset is being consumed in developing exploration and evaluation intangible assets, such gain or loss is recognised as part of the cost of the intangible asset.

The asset's residual values, useful lives and depreciation methods are reviewed, and adjusted if appropriate, at each period end. No depreciation is charged on development assets until production commences.

Depreciation on property, plant and equipment is provided at rates estimated by the management. Depreciation is computed using the straight line method of depreciation, whereby each asset is written down to its estimated residual value evenly over its expected useful life. The useful lives estimated by the management are as follows:

Extended well test equipment	20 years
Bunk houses	5 years
Vehicles	5 years
Other assets
Furniture and fixture	5 years
Buildings	10 years
Computer equipment	3 years
Other equipment	5 years

Land acquired is recognised at cost and no depreciation is charged as it has an unlimited useful life.

Production assets are depreciated from the date of commencement of production, on a field by field basis with reference to the unit of production method for the commercially probable and proven reserves in the particular field.

Advances paid for the acquisition/ construction of property, plant and equipment which are outstanding as at the end of the reporting period and the cost of property, plant and equipment under construction before such date are disclosed as 'Capital work-in-progress'.

5.6. EXPLORATION AND EVALUATION ASSETS

The Group adopts the full cost method of accounting for its oil and gas interests, having regard to the requirements of IFRS 6: Exploration for and Evaluation of Mineral Resources. Under the full cost method of accounting, all costs of exploring for and evaluating oil and gas properties, whether productive or not are accumulated and capitalised by reference to appropriate cost pools. Such cost pools are based on geographic areas and are not larger than a segment. The Group currently has one cost pool being an area of land located in Rajasthan, India.

Exploration and evaluation costs may include costs of licence acquisition, directly attributable exploration costs such as technical services and studies, seismic data acquisition and processing, exploration drilling and testing, technical feasibility, commercial viability costs, finance costs to the extent they are directly attributable to financing these activities and an allocation of administrative and salary costs as determined by management. All costs incurred prior to the award of an exploration licence are written off as a loss in the year incurred.

Exploration and evaluation costs are classified as tangible or intangible according to the nature of the assets acquired and the classification is applied consistently. Tangible exploration and evaluation assets are recognised and measured in accordance with the accounting policy on property, plant and equipment. To the extent that such a tangible asset is consumed in developing an intangible exploration and evaluation asset, the amount reflecting that consumption is recorded as part of the cost of the intangible asset.

Exploration and evaluation assets are not amortised prior to the conclusion of appraisal activities. Where technical feasibility and commercial viability is demonstrated, the carrying value of the relevant exploration and evaluation asset is reclassified as a development and production asset and tested for impairment on the date of reclassification. Impairment loss, if any, is recognised.

5.7. IMPAIRMENT TESTING FOR EXPLORATION AND EVALUATION ASSETS AND PROPERTY, PLANT AND EQUIPMENT

An impairment loss is recognised for the amount by which an asset's or cash-generating unit's carrying amount exceeds its recoverable amount. The recoverable amount is the higher of fair value, reflecting market conditions less costs to sell, and value in use based on an internal discounted cash flow evaluation.

Where there are indicators that an exploration asset may be impaired, the exploration and evaluation assets are grouped with all development/producing assets belonging to the same geographic segment to form the Cash Generating Unit (CGU) for impairment testing. Where there are indicators that an item of property, plant and equipment asset is impaired, assets are grouped at the lowest levels for which there are separately identifiable cash flows to form the CGU. The combined cost of the CGU is compared against the CGU's recoverable amount and any resulting impairment loss is written off in the profit or loss of the year. No impairment has been recognised during the year.

An assessment is made at each reporting date as to whether there is any indication that previously recognised impairment losses may no longer exist or may have decreased. If such indication exists, the Group estimates the asset's or CGU's recoverable amount. A previously recognised impairment loss is reversed only if there has been a change in the assumptions used to determine the asset's recoverable amount since the last impairment loss was recognised. The reversal is limited so that the carrying amount of the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. Such reversal is recognised in profit or loss unless the asset is carried at a re-valued amount, in which case the reversal is treated as a revaluation increase.

5.8. FINANCIAL ASSETS

Financial assets and financial liabilities are recognised on the Group's Statement of Financial Position when the Group has become a party to the contractual provisions of the related instruments.

Financial assets of the Group, under the scope of IAS 39 'Financial Instruments: Recognition and Measurement' fall into the category of loans and receivables. When financial assets are recognised initially, they are measured at fair value plus transaction costs. The Group determines the classification of its financial assets at initial recognition.

Loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. Such assets are subsequently carried at amortised cost using the effective interest method, less provision for impairment. Gains and losses are recognised in profit or loss when the loans and receivables are derecognised or impaired, as well as through the amortisation process.

Loans and receivables are assessed for indicators of impairment at the end of each reporting period. Loans and receivables are considered to be impaired when there is objective evidence that, as a result of one or more events that occurred after the initial recognition, the estimated future cash flows have been affected.

De-recognition of loans and receivables occur when the rights to receive cash flows from the instrument expire or are transferred and substantially all of the risks and rewards of ownership have been transferred.

5.9. FINANCIAL LIABILITIES

The Group's financial liabilities include debts, trade and other payables and loans from related parties.

Financial liabilities are recognised when the Group becomes a party to the contractual agreements of the related instrument.

Financial liabilities are recognised at their fair value less transaction costs and subsequently measured at amortised cost less settlement payments. Amortised cost is computed using the effective interest method.

Trade and other payables and loans from related parties are interest free financial liabilities with maturity period of less than twelve months and are carried at a transaction value that is not materially different from their fair value.

A financial liability is de recognised when the obligation under the liability is discharged or cancelled or expires.

5.10. INVENTORIES

Inventories are measured at the lower of cost and net realisable value. Inventories of drilling stores and spares are accounted at cost including taxes, duties and freight. The cost of all inventories other than drilling bits is computed on the basis of the first in first out method. The cost for drilling bits is computed based on specific identification method.

5.11. SHARE BASED PAYMENTS

The Group operates equity-settled share-based plans for its employees, directors, consultants and advisors. Where persons are rewarded using share-based payments, the fair values of services rendered by employees and others are determined indirectly by reference to the fair value of the equity instruments granted. This fair value is appraised using the Black Scholes model at the respective measurement date. In the case of employees and others providing services, the fair value is measured at the grant date. The fair value excludes the impact of non-market vesting conditions. All share-based remuneration is recognised as an expense in profit or loss with a corresponding credit to 'Share Option Reserve'.

If vesting periods or other vesting conditions apply, the expense is allocated over the vesting period, based on the best available estimate of the number of share options expected to vest. Non-market vesting conditions are included in assumptions about the number of options that are expected to become exercisable. Estimates are subsequently revised, if there is any indication that the number of share options expected to vest differs from previous estimates and any impact of the change is recorded in the year in which that change occurs.

In addition where the effect of a modification leads to an increase in the fair value of the options granted, such increase will be accounted for as an expense immediately or over the period of the respective grant.

Upon exercise of share options, the proceeds received up to the nominal value of the shares issued are allocated to share capital with any excess being recorded as additional paid-in capital.

5.12. ACCOUNTING FOR INCOME TAXES

Income tax assets and/or liabilities comprise those obligations to, or claims from, fiscal authorities relating to the current or prior reporting period that are unpaid / un-recovered at the date of the Statement of Financial Position. They are calculated according to the tax rates and tax laws applicable to the fiscal periods to which they relate, based on the taxable profit for the year. All changes to current tax assets or liabilities are recognised as a component of tax expense in profit or loss.

Deferred income taxes are calculated using the balance sheet method on temporary differences. This involves the comparison of the carrying amounts of assets and liabilities in the financial statement with their tax base. Deferred tax is, however, neither provided on the initial recognition of goodwill, nor on the initial recognition of an asset or liability unless the related transaction is a business combination or affects tax or accounting profit. Tax losses available to be carried forward as well as other income tax credits to the Group are assessed for recognition as deferred tax assets.

Deferred tax liabilities are always provided for in full. Deferred tax assets are recognised to the extent that it is probable that they will be offset against future taxable income. Deferred tax assets and liabilities are calculated, without discounting, at tax rates and laws that are expected to apply to their respective period of realization, provided they are enacted or substantively enacted at the date of the statement of financial position.

Changes in deferred tax assets or liabilities are recognised as a component of tax expense in profit or loss of the year, except where they relate to items that are charged or credited directly to other comprehensive income or equity in which case the related deferred tax is also charged or credited directly to other comprehensive income or equity.

5.13. BORROWING COSTS

Any interest payable on funds borrowed for the purpose of obtaining qualifying assets, which are assets that necessarily take a substantial period of time to get ready for their intended use or sale, is capitalised as a cost of that asset until such time as the assets are substantially ready for their intended use or sale.

Investment income earned on the temporary investment of specific borrowings pending their expenditure on qualifying assets is deducted from the borrowing costs eligible for capitalisation.

Any associated interest charge from funds borrowed principally to address a short-term cash flow shortfall during the suspension of development activities is expensed in the period.

Transaction costs incurred towards an un-utilised debt facility are treated as prepayments to be adjusted against the carrying value of debt as and when drawn.

5.14. CASH AND CASH EQUIVALENTS

Cash and cash equivalents include cash in hand, at bank in demand deposits and deposit with maturities of 3 months or less from inception, which are readily convertible to known amounts of cash. These assets are subject to an insignificant risk of change in value. Cash and cash equivalents are classified as loans and receivables under the financial instruments category.

5.15. LEASING ACTIVITIES

Finance leases which transfer substantially all the risks and benefits incidental to ownership of the leased item, are capitalised at the inception of the lease, at the fair value of the leased property or the present value of the minimum lease payments, whichever is lower.

Lease payments are apportioned between the finance charges and reduction of the lease liability so as to achieve a constant rate of interest on the remaining balance of the liability. Finance charges are charged directly in profit or loss of the year.

All leases other than finance leases are treated as operating leases. Operating lease payments are recognised as an expense in profit or loss on the straight line basis over the lease term.

Where the lease payments in respect of operating leases are made for exploration and evaluation activities or development and production activities, these are capitalized as part of the cost of these assets.

5.16. OTHER PROVISIONS AND CONTINGENT LIABILITIES

Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of a past event, it is probable that an outflow of resources embodying economic benefits will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the Group expects some or all of a provision to be reimbursed, for example under an insurance contract, the reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The expense relating to any provision net of any reimbursement is recognized in profit or loss of the year. To the extent such expense is incurred for construction or development of any asset, it is included in the cost of that asset. If the effect of the time value of money is material, provisions are determined by discounting the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase in the provision due to the passage of time is recognised as other finance expenses.

Provisions include decommissioning provisions representing management's best estimate of the Group's liability for restoring the sites of drilled wells to their original status. Provision for decommissioning is recognised when the Group has an obligation and a reliable estimate can be made. The amount recognised is the present value of the estimated future expenditure. A corresponding item of property, plant and equipment of an amount equivalent to the provision is also recognised and is subsequently depreciated as part of the asset. The unwinding discount is recognised as a finance cost.

Commitments and contingent liabilities are not recognised in the financial statements. They are disclosed unless the possibility of an outflow of resources embodying economic benefits is remote.

A contingent asset is not recognised but disclosed in the financial statements when an inflow of economic benefits is probable but when it is virtually certain than the asset is recognised in the financial statements.

In those cases where the possible outflow of economic resource as a result of present obligations is considered improbable or remote, or the amount to be provided for cannot be measured reliably, no liability is recognised in the statement of financial position and no disclosure is made.

5.17. SEGMENT REPORTING

Operating segments are identified on the basis of internal reports about components of the Group that are regularly reviewed by the chief operating decision maker in order to allocate resources to the segments and to assess their performance. The Company considers that it operates in a single operating segment being the production and sale of gas.

5.18. ADOPTION OF NEW STANDARDS BECOMING APPLICABLE DURING THE YEAR

The Group has adopted the following new standards and amendment to standards, including any consequential amendment to other standards, with a date of initial application from 1 April 2014.

· IFRS 10 Consolidated Financial Statements

IFRS 10 supersedes IAS 27 'Consolidated and Separate Financial Statements' (IAS 27) and SIC12 'Consolidation-Special Purpose Entities'. IFRS 10 revises the definition of control and provides extensive new guidance on its application. These new requirements have the potential to affect which of the Group's investees are considered to be subsidiaries and therefore to change the scope of consolidation. The requirements on consolidation procedures, accounting for changes in non-controlling interests and accounting for loss of control of a subsidiary are unchanged.

Management has reviewed its control assessments in accordance with IFRS 10 and has concluded that there is no effect on the classification (as subsidiaries or otherwise) of any of the Group's investees held during the period or comparative periods covered by these consolidated financial statements.

· IFRS 11 Joint Arrangements

"Joint Arrangements" ("IFRS 11"), which replaces IAS 31, "Interests in Joint Ventures" and SIC-13, "Jointly Controlled Entities - Non-monetary Contributions by Ventures", requires a single method, known as the equity method, to account for interests in joint ventures. The proportionate consolidation method to account for joint ventures is no longer permitted to be used. IAS 28, "Investments in Associates and Joint Ventures", was amended as a consequence of the issuance of IFRS 11. In addition to prescribing the accounting for investments in associates, it now sets out the requirements for the application of the equity method when accounting for joint ventures. The application of the equity method has not changed as a result of this amendment.

The management has made the disclosures as required by IFRS 11 in these consolidated financial statements. There was no impact on the results for the year as a result of the adoption.

· IFRS 12 Disclosure of interests in other entities

IFRS 12 combines the disclosure requirements for subsidiaries, joint arrangements, associates and unconsolidated structured entities within a comprehensive disclosure standard.

It aims to provide more transparency on 'borderline' consolidation decisions and enhance disclosures about unconsolidated structured entities in which an investor or sponsor has involvement.

Subsequent to issuing the new standards the IASB made some changes to the transitional provisions in IFRS 10, IFRS 11, and IFRS 12. The guidance confirms that the entity is not required to apply IFRS 10 retrospectively in certain circumstances and clarifies the requirements to present adjusted comparatives. The guidance also makes changes to IFRS 11 and IFRS 12 which provide similar relief from the presentation or adjustment of comparative information for periods prior to the immediately preceding period. Further, it provides additional relief by removing the requirement to present comparatives for the disclosures relating to unconsolidated structured entities for any periods before the first annual period for which IFRS 12 is applied.

Consequent to adoption of IFRS 12, the management has made these necessary disclosures in the consolidated financial statements.

6. INTANGIBLE ASSETS : EXPLORATION AND EVALUATION ASSETS

Intangible assets comprise of exploration and evaluation assets. Movement in intangible assets is as below:

	Intangible assets: exploration and evaluation assets

Balance as at 1 April 2013	18,427,390
Additions^A	59,380,804
Transfer to development assets ^B	(77,808,194)
Balance as at 31 March 2014	-
Additions^A	34,017,324
Transfer to development assets ^B	(34,017,324)
Balance as at 31 March 2015	-

^AThe above includes borrowing costs of US$ 930,056 (previous year: US$ 2,810,610). The weighted average capitalisation rate on funds borrowed generally is 5.62 per cent per annum (previous year: 6.02 per cent per annum).

^BOn 19 November 2013, Focus Energy Limited submitted an integrated declaration of commerciality (DOC) to the Directorate General of Hydrocarbons, ONGC, the Government of India and the Ministry of Petroleum and Natural Gas. Upon submission of DOC, exploration and evaluation cost incurred on SSF and SSG field was transferred to development cost. Focus continues to carry out further appraisal activities in the Block, and exploration and evaluation cost incurred subsequent to 19 November 2013, to the extent considered recoverable as per DOC submitted by Focus, is immediately transferred on incurrence to development assets.

7. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment comprise of the following:

Cost		Land		Extended well test equipment	Development /Production assets	Bunk Houses	Vehicles^B	Other assets	Capital work-in-progress	Total

Balance as at 1 April 2013		36,437		3,577,517	309,075,831	5,233,802	4,780,493	1,423,900	2,004,272	326,132,252
Additions/transfers		130,811		153,920	98,306,895	150,729	24,009	54,668	426,576	99,247,608
Disposals/transfers		-		-	(317,476)	-	-	-	(1,024,519)	(1,341,995)
Balance as at 31 March 2014		167,248		3,731,437	407,065,250	5,384,531	4,804,502	1,478,568	1,406,329	424,037,865
Additions/transfers		-		6,217	84,319,739	532,992	-	14,180	353,232	85,226,360
Disposals/transfers	-			-	(40,547)	-	(227,699)	-	(569,708)	(837,954)
Balance as at March 2015		167,248		3,737,654	491,344,442	5,917,523	4,576,803	1,492,748	1,189,853	508,426,271
Accumulated Depreciation
Balance as at 1 April 2013			-	709,656	2,149,500	2,943,680	1,778,168	958,165	-	8,539,169
Depreciation for the year			-	334,288	4,773,127	831,921	741,570	235,539	-	6,916,445
Balance as at 31 March 2014			-	1,043,944	6,922,627	3,775,601	2,519,738	1,193,704	-	15,455,614
Depreciation for the year			-	325,707	7,584,042	741,184	358,992	166,259	-	9,176,184
Balance as at 31 March 2015			-	1,369,651	14,506,669	4,516,785	2,878,730	1,359,963	-	24,631,798

Carrying values

At 31 March 2014		167,248		2,687,493	400,142,623	1,608,930	2,284,764	284,864	1,406,329	408,582,251

At 31 March 2015		167,248		2,368,003	476,837,773	1,400,738	1,698,073	132,785	1,189,853	483,794,473

The balances above represent the Group's share in property, plant and equipment as per Note 3.

Tangible assets comprise of development /production assets in respect of SGL field and development assets in respect of SSF and SSG field.

Development assets of SGL field includes the amount of exploration and evaluation expenditure transferred to development cost on the date of the first commercial discovery declared by the Group in 2012 and also includes expenditure incurred for the drilling of further wells in the SGL field to enhance the production activity. Production assets in respect of SGL field includes completed production facilities and under construction Gas gathering station - 2. The Group commenced the production facility in October 2012, and accordingly such production assets have been depreciated since this date.

Development assets of SSF and SSG are explained in Note 6. Pending the assessment of these reserves by the Directorate General of Hydrocarbons, ONGC, the Government of India and the Ministry of Petroleum and Natural Gas and completion of development for production activities, no depreciation has been charged on the same.

The additions in Development/Production assets also include borrowing costs US$14,268,842 (previous year: US$ 10,281,753). The weighted average capitalisation rate on funds borrowed generally is 5.62 per cent per annum (previous year 6.02 per cent).

The depreciation has been included in the following headings-

		31 March 2015	31 March 2014
Depreciation included in exploration and evaluation assets		-	1,602,375
	Depreciation included in development assets	1,592,142	540,943
	Depreciation included in statement of comprehensive income under the head cost of sales	7,584,042	4,773,127
	Total	9,176,184	6,916,445

8. DEFERRED TAX ASSETS/ LIABILITIES (NET)

Deferred taxes arising from temporary differences are summarized as follows:

	31 March 2015	31 March 2014
Deferred tax assets Unabsorbed losses/credits Total Deferred tax liability	177,861,949 177,861,949	142,330,042 142,330,042
Development assets/ property, plant and equipment	204,307,272	155,017,768
Total	204,307,272	155,017,768
Net deferred tax liabilities	26,445,323	12,687,726

a) The Group has recognised deferred tax assets on all of its unused tax losses/unabsorbed depreciation considering there is convincing evidence of availability of sufficient taxable profit in the Group in the future as summarized in Note 9.

b) The deferred tax movements during the current year have been recognised in the Consolidated Statement of Comprehensive income

9. INCOME TAXES

Income tax is based on the tax rates applicable on profit or loss in various jurisdictions in which the Group operates. The effective tax at the domestic rates applicable to profits in the country concerned as shown in the reconciliation below have been computed by multiplying the accounting profit by the effective tax rate in each jurisdiction in which the Group operates. The individual entity amounts have then been aggregated for the consolidated financial statements. The effective tax rate applied in each individual entity has not been disclosed in the tax reconciliation below as the amounts aggregated for individual Group entities would not be a meaningful number.

Income tax credit is arising on account of the following:

	31 March 2015			31 March 2014
Current tax			-		-
Deferred tax charge			(13,757,596)		(9,233,244)
Total		(13,757,596)				(9,233,244)

The relationship between the expected tax expense based on the domestic tax rates for each of the legal entities within the Group and the reported tax expense in profit or loss is reconciled as follows:

	31 March 2015		31 March 2014
Accounting profit for the year before tax		30,002,187		21,005,177
Effective tax at the domestic rates applicable to profits in the country concerned		12,852,937		8,870,486
Impact of change in tax rate on deferred tax		147,873		-
Non allowable expenses		756,786		362,758
Tax expense		13,757,596		9,233,244

The reconciliation shown above has been based on the rate 42.84 per cent (previous year: 42.23 per cent) as applicable under Indian tax laws.

Indus Gas profits are taxable as per the tax laws applicable in Guernsey where zero per cent tax rate has been prescribed for corporates. Accordingly, there is no tax liability for the Group in Guernsey. iServices and Newbury being participants in the PSC are covered under the Indian Income tax laws as well as tax laws for their respective countries. However, considering the existence of double tax avoidance arrangement between Cyprus and India, and Mauritius and India, profits in Newbury and iServices are not likely to attract any additional tax in their local jurisdiction. Under Indian tax laws, Newbury and iServices are allowed to claim the entire expenditure in respect of the Oil Block incurred until the start of commercial production (whether included in the exploration and evaluation assets or development assets) as deductible expense in the first year of commercial production or over a period of 10 years. The Company has opted to claim the expenditure in the first year of commercial production. As the Group has commenced commercial production in 2011 and has generated profits in Newbury and iServices, the management believes there is reasonable certainty of utilisation of such losses in the future years and thus a deferred tax asset has been created in respect of these.

10. INVENTORIES

Inventories comprise of the following:

	31 March 2015	31 March 2014
Drilling and production stores and spares	5,045,918	8,455,623
Fuel	46,703	49,294
Goods in transit	138,794	821,350
Total	5,231,415	9,326,267

The above inventories are held for use in the exploration, development and production activities. These are valued at cost determined based on policy explained in paragraph 5.10.

Inventories of US$ 395,942 (previous year: US$ 224,491) were recorded as an expense under the heading 'cost of sales' in the consolidated statement of comprehensive income during the year ended 31 March 2015.

Inventories of US$ 10,318,743 (previous year: US$ 10,061,574) were capitalised as part of exploration and evaluation assets and development assets.

11. OTHER CURRENT ASSETS

	31 March 2015	31 March 2014
Prepayments for
- debt raising cost	1,011,333	363,762
- others	306,364	44,883
Total	1,317,697	408,645

12. CASH AND CASH EQUIVALENTS

	31 March 2015	31 March 2014
Cash at banks in current accounts	12,251,533	977,028
Total	12,251,533	977,028

The Group only deposits cash surpluses with major banks of high quality credit standing.

13. EQUITY

Authorised share capital

The total authorised share capital of the Company is GBP 5,000,000 divided into 500,000,000 shares of GBP 0.01 each. The total number of shares issued by the Company as at 31 March 2015 is 182,973,924 (previous year: 182,973,924).

--For all matters submitted to vote in the shareholders meeting of the Company, every holder of ordinary shares, as reflected in the records of the Company on the date of the shareholders' meeting has one vote in respect of each share held.

All shareholders are equally eligible to receive dividends and the repayment of capital in the event of liquidation of the individual entities of the Group.

Additional paid in capital

Additional paid-in capital represents excess over the par value of share capital paid in by shareholders in return for the shares issued to them, recorded net of expenses incurred on issue of shares.

Currency translation reserve

Currency translation reserve represents the balance of translation of the entities financial statements into US$ until 30 November 2010 when its functional currency was assessed as GBP. Subsequent to 1 December 2010, the functional currency of Indus Gas was reassessed as US$.

Merger reserve

The balance on the merger reserve represents the fair value of the consideration given in excess of the nominal value of the ordinary shares issued in an acquisition made by the issue of shares of subsidiaries from other entities under common control.

Share option reserve

The amount of share option reserve represents the accumulated expense recognised by the company in its consolidated statement of comprehensive income on account of share based options given by the Company.

Retained earning

Retained earnings include current and prior period retained profits.

14. LONG TERM DEBT FROM BANKS

	Maturity	31 March 2015	31 March 2014
Non-current portion of long term debt	2018/2024	200,293,945	85,266,117
Current portion of long term debt from banks		18,389,976	17,301,889
Total		218,683,921	102,568,006

Current interest rates are variable and weighted average interest for the year was 5.62 per cent per annum (previous year: 6.02 per cent per annum). The fair value of the above variable rate borrowings are considered to approximate their carrying amounts. The maturity profile (undiscounted) is explained in Note 29.

Interest capitalised on loans above have been disclosed in Notes 6 and 7.

The term loans are secured by following:-

· First charge on all project assets of the Group both present and future, to the extent of SGL Field Development and to the extent of capex incurred out of this facility in the rest of RJ-ON/6 field.

· First charge on the current assets (inclusive of condensate receivable) of the Group to the extent of SGL field.

· First charge on the entire current assets of the SGL Field and to the extent of capex incurred out of this facility in the rest of RJON/6 field.

15. PROVISION FOR DECOMMISSIONING

	Provision for decommissioning
Balance as at 1 April 2013	909,515
Increase in provision	170,431
Balance as at 31 March 2014	1,079,946
Increase in provision	201,916
Balance as at 31 March 2015	1,281,862

As per the PSC, the Group is required to carry out certain decommissioning activities on gas wells. The provision for decommissioning relates to the estimation of future disbursements related to the abandonment and decommissioning of gas wells. The provision has been estimated by the Group's engineers, based on individual well filling and coverage. This provision will be utilised when the related wells are fully depleted. The majority of the cost is expected to be incurred within a period of next 9 years. The discount factor being the risk adjusted rate related to the liability is estimated to be 8 per cent for the year ended 31 March 2015 (previous year: 8 per cent).

16. PAYABLE TO RELATED PARTIES

Related parties payable comprise of the following:

	Maturity	31 March 2015	31 March 2014
Current
Liability payable to Focus	On demand	23,446,172	96,783,891
Payable to directors	On demand	44,171	63,914
		23,490,343	96,847,805
Other than current
Borrowings from Gynia Holdings Ltd.*		120,288,834	112,947,262
		120,288,834	112,947,262
Total		143,779,177	209,795,067

Liability payable to Focus

Liability payable to Focus represents amounts due to them in respect of the Group's share of contract costs, for its participating interest in Block RJ-ON/6 pursuant to the terms of Agreement for Assignment dated 13 January 2006 and its subsequent amendments from time to time.

The management estimates the current borrowings to be repaid on demand within twelve months from the statement of financial position date and these have been classified as current borrowings.

* Borrowings from Gynia Holdings Ltd. carries interest rate of 6.5 per cent per annum compounded annually. During the current year, the entire outstanding balance (including interest) was made subordinate to the loans taken from the banks (detailed in Note 14) and therefore, is payable along with related interest subsequent to repayment of bank loan in year 2024. As at 31 March 2014, only US$ 52.6 million was subordinated to loans taken from banks.

Interest capitalised on loans above have been disclosed in Notes 6 and 7.

17. EMPLOYEE COST

Costs pertaining to the employees of Focus have been included in the cost of sales and administrative expenses in the consolidated statement of comprehensive income amounting to US$ 352,458 (previous year US$ 286,366) and US$ 604,906 (previous year US$ 444,466) respectively. Cost pertaining to the employees of the Group have been included under administrative expense is US$ 728,605 (previous year US$ 315,914).

18. FOREIGN CURRENCY EXCHANGE (LOSS)/ GAIN, NET

The Group has recognised the following in the profit or loss on account of foreign currency fluctuations:

	31 March 2015	31 March 2014
(Loss)/gain on restatement of foreign currency monetary receivables and payables	(1,330)	1,423
(Loss)/ gain arising on settlement of foreign currency transactions and restatement of foreign currency balances arising out of Oil block operations	(15,139)	77,466
Total	(16,469)	78,889

19. OPERATING LEASES

Lease payments capitalised under exploration and evaluation assets and development/ production assets during the year ended 31 March 2015 amount to US$ 38,203,891 (previous year US$ 40,284,032). No sublease payments or contingent rent payments were made or received. No sublease income is expected as all assets held under lease agreements are used exclusively by the Group. All the operating leases of the Group can be cancelled and there are no future minimum payments for the existing operating leases. The terms and conditions of these operating leases do not impose any significant financial restrictions on the Group.

20. SHARE BASED PAYMENT

The Company maintains an equity settled share-based payment scheme adopted and approved by the directors on 29 May 2008. Presently, the Company has approved three schemes for the Directors, Consultant and Nominated Advisor known as the "Directors' option agreements", "Advisors Option agreement" and "Arden option deed", respectively. The Company has no legal or constructive obligation to repurchase or settle the options. In accordance with the Plan, upon vesting, the stock options will be settled by the issuance of new shares on payment of the exercise price.

The total amount to be expensed over the vesting period is determined by reference to the fair value of the options granted. The fair values of options granted were determined using the Black Scholes option pricing model that takes into account factors specific to the share incentive plans along with other external inputs. Vesting of these options have completed in earlier years and there is no expense in respect of these options during the years ended 31 March 2015 and 2014.

The total outstanding and exercisable share options and weighted average exercise prices for the various categories of option holders during the reporting periods are as follows:

Share options granted to Directors and Advisors

All the options granted to the Directors and Advisors are fully vested in earlier years. During the year ended 31 March 2015, no option was exercised. The outstanding balance and exercisable share options as at 31 March 2015 and 31 March 2014 were 180,000 shares having a weighted average price of US$ 1.64 per option. These options have expired post year end in June 2015.

Share options granted to Arden Partners

There was no movement in the outstanding options under this category during the year ended 31 March 2015 as the Share options granted to Arden Partners on 28 May 2008 are fully vested and consequently, there is no accounting implication during the reported period. The outstanding balance and exercisable share options granted to Arden Partners as of 31 March 2015 and 31 March 2014 was 76,220 having a weighted average price of US$ 1.64 per option. These options have expired post year end in June 2015.

21. EARNINGS PER SHARE

The calculation of the basic earnings per share is based on the earnings attributable to ordinary shareholders divided by the weighted average number of shares in issue during the year.

Calculation of basic and diluted earnings per share is as follows:

	31 March 2015	31 March 2014
Profits attributable to shareholders of Indus Gas Limited, for basic and dilutive	16,244,591	11,771,933
Weighted average number of shares (used for basic earnings per share)	182,973,924	182,973,924
No of equivalent shares in respect of outstanding options	143,942	55,454
Diluted weighted average number of shares (used for Diluted earnings per share)	183,117,866	183,029,378

Basic earnings per share	0.09	0.06
Dilutive earnings per share	0.09	0.06

22. RELATED PARTY TRANSACTIONS

The related parties for each of the entities in the Group have been summarised in the table below:

Nature of the relationship	Related party's name

I. Holding Company	Gynia Holdings Ltd.

II. Ultimate Holding Company	Multi Asset Holdings Ltd. (Holding Company of Gynia Holdings Ltd.)
III. Enterprises over which Key Management Personnel (KMP) exercise control (with whom there are transactions)	Focus Energy Limited

Disclosure of transactions between the Group and related parties and the outstanding balances as at 31 March 2015 and 31 March 2014 is as under:

Transactions with holding company

Particulars	31 March 2015	31 March 2014
Transactions during the year with the holding company
Interest	7,341,572	6,893,495

Balances at the end of the year
Total payable*	120,288,834	112,947,262
*including interest

Transactions with KMP and entity over which KMP exercise control

Particulars	31 March 2015	31 March 2014
Transactions during the year
Remuneration to KMP
· Short term employee benefits	725,655	315,914
Total	725,655	315,914

Entity over which KMP exercise control
Cost incurred by Focus on behalf of the Group in respect of the Block	65,876,451	68,524,909
Remittances to Focus	138,690,000	26,774,123
Expenses reimbursed	524,170	812,786

Balances at the end of the year
Total payable*	23,446,172	96,783,891

*including interest

Directors' remuneration

Directors' remuneration is included under administrative expenses, evaluation and exploration assets or development assets in the consolidated financial statements allocated on a systematic and rational manner.

Remuneration by director is also separately disclosed in the directors' report on page 12.

23. SEGMENT REPORTING

The Chief Operating Decision Maker, Chief Executive Officer of the Group, reviews the business as one operating segment being the extraction and production of gas. Hence, no separate segment information has been furnished herewith.

All of the non-current assets other than financial instruments and deferred tax assets (there are no employment benefit assets and rights arising under insurance contracts) are located in India and amounted to US$ 483,800,708 (previous year: US$ 408,583,136).

The Group sells natural gas and its by product condensate gas. The natural gas is supplied to a single customer, GAIL, in a single geographical segment, being India. Sale of by product is not significant to be classified as a separate reportable segment.

24. COMMITMENTS AND CONTINGENCIES

The Group has no contingencies as at 31 March 2015 (previous year Nil).

The Group has no commitments as at 31 March 2015 (previous year Nil).

25. RECLASSIFICATION

The statement of financial position as at 31 March 2014 has been restated due to reclassification of tax asset from current classification to non-current. The third statement of consolidated financial position has not been presented since the error pertains to year ended 31 March 2014 and does not have any material impact on the year(s) prior to that.

Detail of this reclassification is summarised below:-

Statement of financial position -

Particulars	31 March 2014	Reclassification	31 March 2014 (Restated)
Current
Tax assets	726,511	(726,511)	-
Non-current
Tax assets	-	726,511	726,511

26. ACCOUNTING ESTIMATES AND JUDGEMENTS

In preparing consolidated financial statements, the Group's management is required to make judgments and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The judgments and estimates are based on management's best knowledge of current events and actions and actual results from those estimates may ultimately differ.

Significant judgments applied in the preparation of the consolidated financial statements are as under:

Determination of functional currency of individual entities

Following the guidance in IAS 21 "The effects of changes in foreign exchange rates" the functional currency of each individual entity is determined to be the currency of the primary economic environment in which the entity operates. In the management's view each of the individual entity's functional currency reflects the transactions, events and conditions under which the entity conducts its business. The management believes that US$ has been taken as the functional currency for each of the entities within the Group. US$ is the currency in which each of these entities primarily generate and expend cash and also generate funds for financing activities.

Full cost accounting for exploration and evaluation expenditure

The Group has followed 'full cost' approach for accounting exploration and evaluation expenditure against the 'successful efforts' method. As further explained in Notes 5.6 and 6, exploration and evaluation assets recorded using 'full cost' approach are tested for impairment prior to reclassification into development assets on successful discovery of gas reserves.

Impairment of tangible assets

The Group follows the guidance of IAS 36 and IFRS 6 to determine when a tangible asset is impaired. This determination requires significant judgment to evaluate indicators triggering impairment. The Group monitors internal and external indicators of impairment relating to its tangible assets. The management has assessed that no such indicators have occurred or exists as at 31 March 2015 to require impairment testing of property, plant and equipment.

Estimates used in the preparation of the consolidated financial statements

Useful life and residual value of tangible assets

The Group reviews the estimated useful lives of property, plant and equipment at the end of each annual reporting period. Specifically, production assets are depreciated on a basis of unit of production (UOP) method which involves significant estimates in respect of the total future production and estimate of reserves. The calculation of UOP rate of depreciation could be impacted to the extent that the actual production in future is different from the forecasted production. During the financial year, the directors determined that no change to the useful lives of any of the property, plant and equipment is required. The carrying amounts of property, plant and equipment have been summarised in Note 7.

Recognition of provision for decommissioning cost

As per the PSC, the Group is required to carry out certain decommissioning activities on gas wells. The ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors including changes to relevant legal requirements, the emergence of new restoration techniques or experience at other production sites. The expected timing and amount of expenditure can also change, for example, in response to changes in reserves or changes in laws and regulations or their interpretation. As a result, there could be adjustments to the provisions established which would affect future financial results. The liabilities estimated in respect of decommissioning provisions have been summarised in Note 15.

Impairment testing

As explained above, the management carried out impairment testing of property, plant and equipment of the Block on 19 November 2013 on submission of integrated declaration of commerciality report by Focus Energy Limited to the Directorate General of Hydrocarbons, ONGC, the Government of India and the Ministry of Petroleum and Natural Gas. An impairment loss is recognized for the amount by which the asset's or cash generating unit's carrying amount exceeds its recoverable amount. To determine the recoverable amount, management estimates expected future cash flows from the Block and determines a suitable interest rate in order to calculate the present value of those cash flows. In the process of measuring expected future cash flows management makes assumptions about future gross profits. These assumptions relate to future events and circumstances. In most cases, determining the applicable discount rate involves estimating the appropriate adjustment to market risk and the appropriate adjustment to asset-specific risk factors.

The recoverable amount was determined based on value-in-use calculations, basis gas reserves confirmed by an independent competent person. Selling price of the gas is based on existing selling price to GAIL which has been agreed for a period of three years which is expiring on September 2015 and henceforth, the prices would be reviewed periodically and reassessed mutually by the parties. The discount rate calculation is based on the Company's weighted average cost of capital adjusted to reflect pre-tax discount rate and amounts to 10% p.a. Management believes that no reasonably possible changes in the assumptions may lead to impairment of property, plants and equipment and intangible assets of the Block.

Deferred tax assets

The assessment of the probability of future taxable income in which deferred tax assets can be utilized is based on the management's assessment, which is adjusted for specific limits to the use of any unused tax loss or credit. The tax rules in the jurisdictions in which the Group operates are also carefully taken into consideration. If a positive forecast of taxable income indicates the probable use of a deferred tax asset, especially when it can be utilized without a time limit, then deferred tax asset is usually recognized in full.

27. BASIS OF GOING CONCERN ASSUMPTION

The Group has current liabilities amounting to US$ 47,126,214 the majority of which is towards current portion of borrowings from banks and related parties, primarily to Focus. As at 31 March 2015, the amounts due for repayment within the next 12 months to banks are US$ 18,389,976, which the Group expects to meet from its internal generation of cash from operations. Further, the Group continues to widen the funding options available and has established a Multicurrency Medium Term Note ("MTN") Programme with the SGX in Singapore for up to US$ 300 Million. Out of which, the Group has successfully placed SGD 100 Million Senior Unsecured Notes as first tranche of the MTN Programme, subsequent to the year end. The net proceeds will be utilised towards further development expenditure on the Block. Depending upon the funding requirement and subject to potential availability of financing on reasonable terms, the Group may draw further tranches against this MTN Programme in future. Based on this, the consolidated financial statements have been prepared on the going concern basis.

28. CAPITAL MANAGEMENT POLICIES

The Group's objectives when managing capital are to safeguard the Group's ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital.

The Group manages the capital structure and makes adjustments to it in the light of changes in economic conditions and the risk characteristics of the underlying assets. The Group monitors capital on the basis of the gearing ratio. This ratio is calculated as net debt divided by total capital.

Debt is calculated as total liabilities (including 'current and non-current liabilities' as shown in the consolidated Statement of Financial Position). Total equity is calculated as 'equity' as shown in the consolidated Statement of Financial Position plus total debt.

	31 March 2015	31 March 2014
Total debt (A)	421,000,173	355,953,141
Total equity (B)	88,160,440	71,915,850
Total capital employed (A+B)	509,160,613	427,868,991
Gearing ratio	82.69 per cent	83.19 per cent

The gearing ratio has marginally reduced since the previous year due to proportionately greater increase in equity as compared to increase in the draw-down of loans from banks and related party to fund additional exploration, evaluation and development activities for the Group.

The Group is not subject to any externally imposed capital requirements. There were no changes in the Group's approach to capital management during the year.

29. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

A summary of the Group's financial assets and liabilities by category are mentioned in the table below:

The carrying amounts of the Group's financial assets and liabilities recognised at the end of the reporting period are as follows:

	31 March 2015	31 March 2014
Non-current assets
Loans and receivables
- Security deposits	6,225	885
Current assets
Loans and receivables
- Trade receivables	5,330,484	7,847,404
- Cash and cash equivalents	12,251,533	977,028
Total financial assets under loans and receivables	17,588,242	8,825,317
Non-current liabilities
Financial liabilities measured at amortised cost:
- Long term debt from banks	200,293,945	85,266,117
- Payable to related parties	120,288,834	112,947,262
Current liabilities
Financial liabilities measured at amortised cost:
- Current portion of long term debt from banks	18,389,976	17,301,889
- Current portion of payable to related parties	23,446,172	96,783,891
- Accrued expenses and other liabilities	168,809	126,478
Total financial liabilities measured at amortised cost	362,587,736	312,425,637

The fair value of the financial assets and liabilities described above closely approximates their carrying value on the statement of financial position date.

Risk management objectives and policies

The Group finances its operations through a mixture of loans from banks and related parties and equity. Finance requirements such as equity, debt and project finance are reviewed by the Board when funds are required for acquisition, exploration and development of projects.

The Group treasury functions are responsible for managing fund requirements and investments which includes banking and cash flow management. Interest and foreign exchange exposure are key functions of treasury management to ensure adequate liquidity at all times to meet cash requirements.

The Group's principal financial instruments are cash held with banks and financial liabilities to banks and related parties and these instruments are for the purpose of meeting its requirements for operations. The Group's main risks arising from financial instruments are foreign currency risk, liquidity risk, commodity price risk and credit risks. Set out below are policies that are used to manage such risks:

Foreign currency risk

The functional currency of each entity within the Group is US$ and the majority of its business is conducted in US$. All revenues from gas sales are received in US$ and substantial costs are incurred in US$. No forward exchange contracts were entered into during the year.

Entities within the Group conduct the majority of their transactions in their functional currency other than finance lease obligation balances which are maintained in Indian Rupees and amounts of cash held in GBP. All other monetary assets and liabilities are denominated in functional currencies of the respective entities. The currency exposure on account of liabilities which are denominated in a currency other than the functional currency of the entities of the Group as at 31 March 2015 and 31 March 2014 is as follows:

	Functional currency	Foreign currency	31 March 2015	31 March 2014
Total exposure			62,406	89,424
Short term exposure	US$	Great Britain pound	62,406	89,424

The Group's currency exposure risk towards GBP is insignificant and accordingly the movement in foreign currency will not have a material impact on the consolidated financial statements.

Liquidity risk

Ultimate responsibility for liquidity risk management rests with the Board of Directors, which has established an appropriate liquidity risk management framework for the management of the Group's short-, medium- and long-term funding and liquidity management requirements. The Group manages liquidity risk by maintaining adequate reserves, banking facilities and reserve borrowing facilities, by continuously monitoring forecast and actual cash flows, and by matching the maturity profiles of financial assets and liabilities.

The table below summaries the maturity profile of the Group's financial liabilities based on contractual undiscounted payments for the liquidity analysis

	On demand	1-3 months	3 months to 1 year	1-5 years	5+ years	Total
31 March 2015
Non-interest bearing	-	168,809	-	-	-	168,809
Variable interest rate liabilities	23,446,172	4,689,367	13,766,519	147,229,561	57,136,920	246,268,539
Fixed interest rate liabilities	-	-	-	-	120,288,834	120,288,834

	23,446,172	4,858,176	13,766,519	147,229,561	177,425,754	366,726,182

	On demand	1-3 months	3 months to 1 year	1-5 years	5+ years	Total
31 March 2014
Non-interest bearing	-	126,478	-	-	-	126,478
Variable interest rate liabilities	96,783,891	4,857,924	14,273,906	58,573,526	26,076,167	200,565,414
Fixed interest rate liabilities	-	-	-	-	112,947,262	112,947,262

	96,783,891	4,984,402	14,273,906	58,573,526	139,023,429	313,639,154

Interest rate risk

The Group's policy is to minimize interest rate risk exposures on the borrowing from the banks and the sum payable to Focus Energy Limited. Interest rate on the sum payable to Focus Energy Limited is linked to actual interest incurred by Focus capped between 6.5 per cent and 10 per cent on the chargeable sum (as defined under amendment in agreement for assignment of participating interest). Borrowing from the Gynia Holdings Ltd. is at fixed interest rate and therefore, doesn't expose the Group to risk from changes in interest rate. The Group is exposed to changes in market interest rates through bank borrowings at variable interest rates. Interest rate on US$ 110 million bank borrowing is 5 per cent plus LIBOR; on US$ 40 million bank borrowing is 4 per cent plus LIBOR and on US$ 180 million bank borrowing is 4.1 per cent plus LIBOR (detailed in Note 14).

The Group's interest rate exposures are concentrated in US$.

The analysis below illustrates the sensitivity of profit and equity to a reasonably possible change in interest rates. Based on volatility in interest rates in the previous 12 months, the management estimates a range of 50 basis points to be approximate basis for the reasonably possible change in interest rates. All other variables are held constant.

	Interest rate
	+ 0.50 per cent	- 0.50 per cent
31 March 2015	1,694,864	(1,694,864)
31 March 2014	996,759	(996,759)

Since the loans are taken specifically for the purpose of exploration and evaluation, development and production activities and according to the Group's policy the borrowing costs are capitalised to the cost of the asset and hence changes in the interest rates do not have any immediate adverse impact on the profit or loss.

Commodity price risks

The Group's share of production of gas from the Block is sold to GAIL. The price has been agreed for a period of three years which is expiring in September 2015 and henceforth, the same would be reviewed periodically and reassessed mutually by the parties. No commodity price hedging contracts have been entered into.

Credit risk

The Group has made short-term deposits of surplus funds available with banks and financial institutions of good credit repute and therefore, doesn't consider credit risk to be significant. Other receivables such as security deposits and advances with related parties, do not comprise of a significant cumulative balance and thus do not expose the Group to a significant credit risk. The Group has concentration of credit risk as all the Group's trade receivables are held with GAIL, its only customer. However, GAIL has a reputable credit standing and hence the Group does not consider credit risk in respect of these to be significant. None of the financial assets held by the Group are past due.

30. SUBSEQUENT EVENTS

Subsequent to year end 31 March 2015, the Company has established a Multicurrency Medium Term Note ("MTN") Programme with the SGX in Singapore and raised SGD 100 million (refer Note 27 for details).

This information is provided by RNS

The company news service from the London Stock Exchange

END

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