Indus Gas Regulatory News (INDI)

For Immediate Release 18 September 2013

Indus Gas Limited

("Indus" or "the Company")

Preliminary Financial Results

Indus Gas Limited (AIM:INDI.L), an oil & gas exploration and development company with assets in India, is pleased to report its full year results for the 12 months to 31 March 2013.

Highlights

SGL Field Development

· Gas prices are expected to increase to US$ 8.4 per mmbtu in FY 2014-15 and above US$ 10 per mmbtu for FY 2015-16 onwards post Government approval - expected to be reflected in new gas sales contract being negotiated and existing contracts post renewal in October 2015.

· Production ramp up completed in September 2012 including installation of a CO2 removal facility of 65 mmcf/d. These facilities are in respect of Phase II gas sales quantities of 33.5 mmcf/d contracted with GAIL (India) Ltd. Notice for 'Take or Pay (ToP)' for the second phase of production became effective from 1st October 2012. Indus share of the ToP revenue invoiced during FY -2012-13 is US$ 11.66 mn.

· 2P reserves increased from 307 bcf to 573 bcf, an increase of approximately 86%, whereas the total reserves/resources have increased from 4.273 tcf to 5.454 tcf, an increase of approximately 27.6%, as published in the updated CPR in December 2012.

· Successful drilling of a number of new appraisal and development wells.

· On-going negotiation for supply of additional 28 mmscfd (net of CO2) to state owned power company 'Rajasthan Rajya Vidyut Utpadan Nigam Limited (RRVUNL)' through GAIL is in advanced stages. With the approval of the new regulated Gas pricing formula, the way for the signing of this contract has also been cleared. The turbine for additional 160 MW capacity has already reached the RRVUNL premises at Ramgarh and the installation is to begin soon.

Operational (Cumulative as on 31st March 2013)

· Acquired, processed and interpreted 1630.53 km2 of 3D seismic data as of 31March 2013, with additional 18.09 km2 of 3D seismic data acquired between April-July 2013.

· Acquired, processed and interpreted 1,037.275 line km of 2D seismic data.

· During the year completed eight appraisal wells and three development wells. A total of 40 appraisal and development wells have been drilled as of 31st March 2013 averaging3,441 meters per well.

Financial

· Adjusted consolidated revenues, operating profit and profit before tax of respectively US$ 19.72mn, US$16.20mn & US$ 14.73mn after considering and including a management adjustment for "ToP" receipts of US$ 11.66 mn for the year. Reported consolidated revenues, operating profits & profit before tax of respectively US$ 8.06 mn, US$ 4.54 mn & US$ 3.07 mn for the year excluding "Take or Pay" amount. Provision of notional deferred tax liability of US$ 1.68 mn as per IFRS requirements. Given the Group's carried forward capital depreciation allowances, management believes this is not likely to be payable for many years if at all.

· Total net cash investment of US$ 80.17mn during the year in respect of appraisal and development of the Block. Partly financed from net incremental loans from banks of US$ 21.98 mn and increase in related party unsecured loans and payables of US$ 59.09 mn.

· Principal and Interest payments of term loan facilities amounted to US$ 17.32 mn and US$ 6.71 mn, respectively.

Commenting, Marc Holtzman, Chairman of Indus, said:

"It has been another successful year for Indus Gas. The Company's focus has been on securing as much of the Block as possible, after the end of the appraisal period, for development through appraisal drilling and to increase production from the SGL Field to meet the uplift in sales to 33.5mmcf/d under phase II of the programme. Both where successfully achieved and the latter is reflected in the Company's revenues and profits in the second half of the year. Looking ahead, there will be continued focus on appraisal drilling, well testing and also on securing the additional sales contract, in which we expect the new approved price increase for gas in India to be reflected"

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 20 years of industry experience is the qualified person that has reviewed the technical information contained in this release.

For further information please contact:

Background Information

Indus Gas Limited ("Indus") is focused on oil and gas exploration and development in Rajasthan, India in Block RJ-ON/6. Indus owns 90% participating interest in the Block (excluding SGL gas field, in respect of which its participating interest is 63%). Other partners in the block are (i) Focus Energy Ltd., which operates the Block, and (ii) Oil and Natural Gas Corporation (ONGC), India, which is the licensee of the Block. The 'Participative Interest' of Indus as mentioned above is held through its wholly owned subsidiaries i.e. iServices Investment Limited and Newbury Oil Company Limited. The Block currently measures an area of 4,026 km² and lies onshore in the highly prospective mid Indus Basin. The first discovery in the block was made in 2006 and the first commercial production commenced in 2010. As per the reserve estimation report by Senergy Plc of UK published in December 2012, the 2P recoverable reserves, 2C contingent & best estimate prospective resources in the block are 5.45 tcf of gas.

RESULTS STATEMENT

Introduction

We have had another active year and I am pleased to report significant progress across several areas. Our stated business plan remains on track and 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. We have successfully started the second phase of production, as per the 'Gas Sale Contract' with GAIL, and the enhanced revenue/receipts commenced from 1st October 2012. We have also continued with our appraisal program and have completed significant drilling and testing, confirming and establishing further gas presence. During the year, we also obtained a new reserve report which significantly increased our reserves and resources. A summary of activities since April 2012 is provided below:

SGL Field Development

During the year, a total quantity of 2,444 mmscf of gas was produced from the field and supplied to GAIL. There were no major breakdowns and our buyer met their respective obligations under the 'ToP' agreement. The ToP obligation on the second phase production for GAIL started from 1st October and the Company invoiced a total ToP amount of US$ 11.66 mn in addition to the sales revenue of US$ 8.06 mn from gas supplies, during the year. With the start of the second phase, the price of gas has also gone up to US$ 5.00 per mmbtu.

For implementation of this Phase II, the required Gas Gathering Station ('GGS') including the gas processing plant, the CO2 removal plant and other equipment has been successfully installed. A sufficient number of production wells have also been drilled and completed.

As part of its future gas development, the Company is negotiating for another off take agreement with GAIL for the supply of an additional 28 mmscfd (net of CO2) gas for a new 160 MW power plant proposed to be set up in Ramgarh, alongside the existing power generation capacity of 270 MW. The ultimate gas buyer, Rajasthan Rajya Vidyut Utpadan Nigam Limited (RRVUNL), the State Electricity Company in Rajasthan, has already received the turbine and is soon to start its installation. This plant is solely based on the enhanced gas supplies from the SGL field. There is no other source of gas nearby and the imported gas is very costly, with no pipeline infrastructure to transport imported gas. The recent price increase approval by the Indian Government will greatly help in finalizing and the signing of this new off take agreement.

Drilling, Seismic, Completion Operations and Reserves

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

a) appraisal drilling covering as large an area as possible to be able to retain the maximum potential development area upon completion of the appraisal phase in late 2013 under the Production Sharing Contract;

b) drilling and completion of production wells for the SGL Field Development continued as planned to meet contracted 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. Some of these new prospects have been drilled or are being drilled and a few more are proposed to be drilled soon. Some of the existing formation which had earlier shown encouraging results have been further drilled and tested. A number of wells drilled during the year have shown the presence of gas.

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

SGL-9 (3155m) Gas Producer (Pariwar)

Well SGL-9 terminated at 3155 metres within the uppermost parts of the P10 Reservoir zone. The well was completed with a barefoot open hole completion from 3048-3152m which covered the P20 zone and the uppermost P10 reservoir zone. The well is currently flowing from the P10 and P20 reservoir zones.

SGL-10 (3311m) Gas Producer (Pariwar)

SGL-10 terminated at 3311m within the lowermost parts of the Pariwar P10 Reservoir Zone. The well was cased and a zone from 3171-3176m within the P20 reservoir zone was perforated and completed for production. This interval is currently on production.

SGL-2A (3895m) Gas Producer (Pariwar)

SGL-2A was drilled to 3895m, terminating within the upper B&B Formation. The well encountered gas shows within the Upper B&B Target sands and the Pariwar Formation reservoir sands. The well was cased and a zone from 3163-3169m within the P10 Reservoir zone was perforated and completed for production and is producing currently.

SX-3 (3606m) Gas Shows (Pariwar Formation)

Well SX-3 is located in the extreme south-western parts of Block RJ-ON/6. The primary aim of this well was to test Pariwar reservoir sands in which gas shows were encountered in nearby SX-2, but completion complications in that well led to test results being inconclusive. Gas was encountered in the same Pariwar reservoir zones in SX-3 and subsequently an interval from 3294-3299m was selected for perforation. This interval has flowed gas to surface during testing. Testing of additional intervals will be undertaken soon to determine commerciality.

SU-1(SUHF-1) (4003m) Gas Shows (Pariwar and B&B Formations)

Appraisal well SU-1 terminated in the lower B&B sands and encountered gas shows within the Pariwar and B&B Formations. At present, one zone from the lower B&B Formation target interval has been perforated from 3867-3870m and gas has been recovered to surface from this zone but with low rates of flow. This interval is currently under assessment for further testing and potential hydro fracture stimulation. On the basis of well log analysis one further zone in the lower B&B, plus two upper B&B and two additional Pariwar Formation zones have been identified as potential targets for further testing.

S - 97 (3341m) Gas Shows (Pariwar Formation)

S-97 terminated in the upper parts of the Pariwar Formation in which key gas shows were encountered from the target reservoir zones. An initial open hole Drill Stem Test (DST) from 3129-3182m flowed gas to surface with a FTHP of 200 psi on a 2" choke. A subsequent zone from 3175-3178m was perforated which flowed gas and water to surface. This well is under review for further testing.

EP - 2A(4146m) Gas Shows (Pariwar and B&B Formation)

Key gas shows have been encountered in the main Pariwar reservoir zones and the upper B&B Formation sands in well EP-2A, with two zones (3808-3811m and 3846-3870m) currently high-graded for further testing in the upper B&B Formation.

PR - 2 (3269 m) Gas shows (Pariwar Formations)

PR-2 terminated in the upper parts of the Pariwar Formation in which key gas shows were encountered in the main P10 Pariwar reservoir zone sands. A perforation interval from 3157m-3165m successfully flowed gas to surface but sustained flow rates were low. This interval and an additional interval with good gas shows based on wire line log analysis are under review for further testing and potential hydro fracturing stimulation. 

NQL -1 (3635 m) Gas shows (Pariwar Formations)

Well NQL-1 terminated in the uppermost B&B Formation. The well has encountered multiple zones with gas shows based on drill shows and wire line log analysis, with eight potential zones in total are currently under review for further testing.

Brent - 1 (3254 m) Dry Hole Minor Gas shows only

Well BRENT-1 terminated in the uppermost Jaisalmer Formation. This well was drilled in a structurally shallow/up-dip location to the east of the other wells in RJ-ON/6 to test the eastern extent of the Pariwar/B&B Petroleum System. Minor gas shows were encountered in the Pariwar P10 reservoir zone and mid B&B Formation but no objects have been currently identified for further testing.

LILOI -1 (3384 m) Gas shows (Pariwar Formations)

Key gas shows were encountered in LILOI-1 well in the main Pariwar P10 reservoir zone in which the well terminated. A zone from 3157-3165m was perforated which has flowed gas to surface, albeit with sub-commercial flow rates recorded to-date. This zone and two further Pariwar P10 reservoir intervals are currently under review for further testing.

During the year, the Company has completed eight appraisal wells, and has encountered gas shows in a large number 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, once the appraisal period comes to an end by the end of this year. This will also help us in establishing more 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.

In December 2012, Indus published an updated reserves report, reflecting work done since 2010 but, due to timing, excluded wells drilled outside the SGL area in the second half of 2012. The report saw a significant increase in both reserves and resources, with gross 2P reserves increased to 573 Bcf from 307 Bcf in 2010. Net 2P reserves increased from 210 Bcf to 449 Bcf. 2C gross contingent resource also saw a meaningful increase, from 1,808 Bcf to 2,699 Bcf, and over 1 Tcf of gross prospective resource was attributed to wells outside the SGL development area.

Financials

During the financial year, the Company supplied 2,444 mmscf of gas and invoiced revenues of US$ 8.06 mn (2011/12 US$ 6.76 mn), resulting in reported operating profit of US$ 4.54 mn (2011/12 US$3.98 mn]. The reported profit after tax was US$ 1.39 mn (2011/12 US$1.36 mn] after considering foreign exchange gains of US$ 0.03 mn and interest costs of US$ 1.49 mn.

Indus additionally received take or pay payment of US$ 11.66mn for the period, which is considered as deferred revenues and shown as liabilities since these receipts can be potentially 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 set off can be made. An amount of US$ 5.08 mn is shown as current liabilities and the remaining US$ 6.58 mn is shown 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 & profit adjustment and accordingly adjusted consolidated revenues, operating profit and profit before tax for the year were respectively US$ 19.72mn, US$16.20mn & US$ 14.73mn after including "ToP" amount of US$ 11.66 mn. .

While, the Company is not expected to pay any significant taxes on its income for many years, in view of 100% deduction allowed under Indian income tax act on the capital expenses in the Block, the Company has accrued notional non-cash deferred tax liability of US$ 1.68 mn as per IFRS requirements.

Post this deferred tax liability provision, the net profit for the year was US$ 1.39 mn.

The expenditure on exploration and evaluation assets during the year was US$ 53.57mn. Also subsequent to the certification of new 2P reserves of 266 bcf in the SSF area, within the SGL field, an amount of US$ 76.14 mn has been transferred from exploration and evaluation assets to development assets. The value of development assets and other tangible plant and machinery has increased US$ 105.19 mn, including the amount of US$ 76.14 mn transferred from exploration and evaluation assets as mentioned above, during the period. The development assets amortised on the gas produced during the year was US$ 1.51 mn.

The current assets (excluding cash) as of 31 March 2013 stood at US$ 16.17 mn, which includes US$ 5.97 mn of inventory and US$ 9.93 mn of trade receivables. The trade receivables are mainly on account of receivables of the fourth quarter ToP amount of US$ 6.15 mn and the 'Annual ToP' amount of US$ 2.80 mn billed on the last day of the year. The current liabilities of the Company, excluding the related party liability of US$ 55.85 mn and current portion of long term debt of US$ 16.96 mn, stood at US$ 5.14 mn. This comprised mainly of deferred revenue of US$ 5.08 mn and accrued expenses and liabilities of US$ 0.06 mn.

As of 31 March, the outstanding term loan of the Company was US$ 119.18 mn, out of which US$ 16.96 mn was categorised as repayable within a year and the remaining US$ 102.22 mn has been categorised as long term liability. The Company utilised a term loan of US$ 40 mn during the year and its repayment has commenced from June 2012.During the year, the Company has repaid an amount of US$ 17.32 mnof the outstanding term loan facilities, as per the scheduled repayment plan.

In view of the delay in the implementation of Phase II, the funding requirements of the Company were met primarily through continued financial support from Gynia Holdings Ltd. ("Gynia") (a significant shareholder and a related party). Accordingly, the amount payable to Gynia has increased by US$ 63.51mn from US$ 42.54mnfrom 31 March 2012 to US$ 106.05mnas of 31 March 2013.The Gynia loan is unsecured and carries an interest calculated @ 6.5% per annum which is accrued and will be paid only at final maturity of the loan amount. Out of this payable, an amount of US$ 52.6 mn is subordinated to the bank term loan and is repayable (both interest and principal) only after the entire term loan availed from the bank lenders have been paid off. The balance of the Gynia loan is payable in the year ending 31 March 2019.

In addition to the Gynia Loan, the Company has a short term facility payable of US$ 55.85mn (FY 2011-12: US$59.40mn) due to Focus Energy Ltd. ("Focus"), a related party. Focus is the Operator of the block and Indus is obliged to bear its proportion of the costs and expenses borne by the Operator in respect of the block. An interest amount of 6.5% is payable on the outstanding amount due to Focus, in accordance with the operating and assignment agreement for the block. Both the Gynia loan and Focus payables are contracted on usual commercial terms and on an arm's length basis.

Indus expects to meet its capital investment requirements during FY 2013-14, primarily from loans and revenues from gas sales. The Company also expects to be able to contract additional debt financing from banks/institutions for the expenditure proposed to be incurred for FY 2013-14 and onwards. With the start of the second phase of production, the Company has sufficient cash flows to be able to support additional debt.

Outlook

During the next twelve months, we look forward to continuing the extensive appraisal drilling and testing campaign to be able to establish the maximum potential development area and additional reserves. This will be critical from the perspective of retaining as much prospective area of the block as possible after the appraisal period end in late 2013. We also look forward to progressing and concluding discussions with GAIL for the supply of additional quantities of gas to the RRVUNL owned power plant expansion.

AJAY KALSI

Chief Executive Officer

17th September 2013

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 year ended 31 March 2013 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

Respective responsibilities of directors and auditors

As described in the Statement of Directors' Responsibilities on page 10 the company's directors are responsible for the preparation of the consolidated financial statements and for being satisfied that they give a true and fair view.

Our responsibility is to audit and express an opinion on the consolidated financial statements in accordance with applicable legal and regulatory requirements 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. 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 2013 and of its profit for the year then ended;

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

· have been prepared in accordance 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 matters where The Companies (Guernsey) Law, 2008 requires us to report to you, if in our opinion:

· the group has not kept proper accounting records; or

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

· we have not received 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

17 September 2013

Consolidated Statement of Financial Position

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

(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 17 September 2013 and was signed on its behalf by:

Director

Consolidated Statement of Comprehensive Income

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

(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)

(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)

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

AThe movement of property, plant and equipment above, excludes the non-cash transfer from exploration and evaluation assets during the year, as explained in Note 6.

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 Ltd. ("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 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 endorsed by the European Union ('EU'). The consolidated financial statements have been prepared on a going concern basis, 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 is jointly engaged in oil and gas exploration, development and production activities along with Focus. This venture is a jointly controlled asset as defined under IAS 31: Interest in Joint Ventures. 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 on 6 June 2008 had exercised the option to acquire a 30 per cent participating interest in the discovered fields.

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 such 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.

On the basis of above, gas production of the year ended 31 March 2013 is shared between Focus, iServices and Newbury in the ratio of 10 percent, 65 percent and 25 percent, 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:

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 until the date of approval of these consolidated financial statements 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, amendments and interpretations that are expected to be relevant to the Group's consolidated financial statements is provided below.

IFRS 9 Financial Instruments (Issued November 2009) (Effective from 1 January 2015 (but under exposure draft)

The IASB aims to replace IAS 39 Financial Instruments: Recognition and Measurement in its entirety with the replacement standard to be effective for annual periods beginning 1 January 2015. IFRS 9 is the first part of Phase 1 of this project.

The main phases are:

Phase 1: Classification and measurement

Phase 2: Impairment methodology

Phase 3: Hedge accounting

In addition, a separate project is dealing with de-recognition. Management has yet to assess the impact that this amendment is likely to have on the financial statements of the Group. However, they do not expect to implement the amendments until all chapters of the IAS 39 replacement have been published and they can comprehensively assess the impact of all changes.

Amendment (issued 28 October 2010) (Effective from 1 January 2015 (but under exposure draft))

In October 2010, the IASB amended IFRS 9 to incorporate requirements for classifying and measuring financial liabilities and derecognising financial assets and financial liabilities. Most of IAS 39's requirements have been carried forward unchanged to IFRS 9. Changes have however been made to address issues related to own credit risk where an entity takes the option to measure financial liabilities at fair value.

IFRS 10 Consolidated financial statements (Issued May 2011) (Effective from 1 January 2013)

IFRS 10 introduces a revised definition of control together with accompanying guidance on how to apply it. In contrast to IAS 27 and SIC-12, which resulted in different criteria for determining control being applied to special purpose vehicles, IFRS 10's requirements will apply to all types of potential subsidiaries.

Though the standard is applicable to the Group the changes in the new standard from the last version are not likely to have an effect on the Group.

IFRS 11Joint Arrangements (Issued May 2011) (Effective from 1 January 2013)

IFRS 11 supersedes IAS 31 Interests in Joint Ventures. It replaces IAS 31's three categories of 'jointly controlled entities', 'jointly controlled operations' and 'jointly controlled assets' with two new categories - 'joint operations' and 'joint ventures'. The option of using proportionate consolidation for jointly controlled entities that was previously included in IAS 31 has been eliminated (equity accounting is now required for all joint ventures. Though the standard is applicable to the Group the changes in the new standard from the last version are not likely to have an effect on the Group.

IFRS 12 Disclosure of Interests in Other Entities (Issued May 2011) (Effective from 1 January 2013)

The new standard integrates and makes consistent the disclosure requirements for subsidiaries, joint arrangements, associates and unconsolidated structured entities. The new standard is intended to provide transparency about the risks to which a reporting entity is exposed from its involvement with structured entities. The Group will be required to make additional disclosures as suggested by this new standard.

IFRS 13 Fair Value Measurement (Issued May 2011) (Effective from 1 January 2013)

The new IFRS does not affect which items are required to be 'fair-valued', but specifies how an entity should measure fair value and disclose fair value information. IFRS 13 has been developed to remedy this problem, by establishing a single source of guidance for all fair value measurements, clarifying the definition of fair value and related guidance and enhancing disclosures about fair value measurements (new disclosures increase transparency about fair value measurements, including the valuation techniques and inputs used to measure fair value).

The guidance in the standard would impact how the Group would fair value its financial instruments and give disclosures that are required by this standard, however considering the transactions in the Group, this standard is not likely to have an impact on the Group.

Consequential amendments to IAS 27 Consolidated and Separate Financial Statements and IAS 28 Investments in Associates and Joint Ventures (Issued May 2011) (Effective from 1 January 2013)

IAS 27 now only deals with separate financial statements. IAS 28 brings investments in joint ventures into its scope. However, IAS 28's equity accounting methodology remains unchanged.

The Group's management has yet to assess the impact of these new and revised standards on the Group's consolidated financial statements, however these are not likely to have an impact on the consolidated financial statements of the Group.

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 2013. Subsidiaries are all entities over which the Group has the power to control the financial and operating policies. Indus Gas obtains and exercises control through more than half of the voting rights. All subsidiaries have a reporting date of 31 March.

Unrealised gains and losses on transactions between Group companies are eliminated. Where unrealised losses on intra-group asset sales are reversed on consolidation, the underlying asset is also tested for impairment from a group perspective. 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 effective date of acquisition, or up to the effective date of disposal, as applicable.

5.2. SIGNIFICANT ACCOUNTING JUDGEMENTS AND ESTIMATES

In preparing consolidated financial statements, Group's management is required to make judgments, 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 of 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 judgments, 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 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 generally 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.

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 till 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:

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

Production assets are being 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 and also taking into account the future development costs to be incurred on these respectively for the probable and proven reserves, (taken at the current price). Changes in the prices and quantities are applied prospectively to future periods.

Advances paid for the acquisition/ construction of property, plant and equipment which are outstanding at the consolidated Statement of Financial Position date 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 license 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 license are written off as loss of the year as 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 assets and any impairment loss 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 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, bank overdrafts, 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 transaction value which is not materially different from their fair value.

A financial liability is derecognised 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

Current 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 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 un-utilised debt facility is 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 and at bank in demand deposits, 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. 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 of the 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 in the financial statements but disclosed when an inflow of economic benefits is probable.

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.

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6. INTANGIBLE ASSETS : EXPLORATION AND EVALUATION ASSETS

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

The above additions include borrowing costs capitalised of US$ 3,769,364 (previous year: US$ 1,584,671) during the year. The weighted average capitalisation rate on funds borrowed is 5.8 per cent per annum (previous year 5.9 per cent).

The Group has a valid appraisal license till November 2013 and accordingly it is continuing to carry on exploration, evaluation and appraisal activities along with the development and production activities on the commercially viable reserves within the same Block.

A Based on a study conducted by an independent expert and their report on 03 December 2012, the Group believes that gas reserves discovered in the SSF field in the Block are technically feasible and commercially viable. Accordingly, the Group has reclassified the balance of exploration and evaluation costs as at 30 November 2012 into development assets. Focus intends to file an integrated development plan along with its evaluation of commerciality of all gas discoveries to the Management Committee (comprising of representatives of, inter alia, Newbury, iServices, Focus, ONGC and DGH) as required by the PSC prior to the or upon completion of the appraisal period.  

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7. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment comprise of the following:

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

B Tangible assets comprising of development/ production assets represent the amount of exploration and evaluation expenditure incurred and accumulated up to the date of the first commercial discovery declared by the Group on 21 January 2008 in respect of SGL field. Since ONGC has exercised the option to acquire a 30 per cent participating interest in the discovered field, accordingly the additions to development and production assets represents 63 per cent of the total cost incurred by the participating parties. Further, the additions during the year include the expenditure incurred for drilling of further wells in the SGL field to enhance the production activity. Also included under development and production assets are completed additional production facilities (gas gathering station - 2) in respect of the SGL field. The Group commenced production from the new facility from 1 October 2012, and accordingly such production assets have been depreciated since this date.

As mentioned in note 6, during the year ended 31 March 2013, development assets also include a transfer from exploration and evaluation assets, in respect of the SSF field, consequent to the commercial viability and technical feasibility of the reserves in the field, based on the report of an independent expert and the evaluation made by Group's management in respect of these reserves. Pending the assessment of these reserves by the Management Committee and completion of development for production activities, no depreciation has been charged on the same.

Development/Production assets also include borrowing costs capitalised of US$ 8,699,988 (previous year: US$ 7,416,354). The weighted average capitalisation rate on funds borrowed is 5.8 per cent per annum (previous year 5.9 per cent).

CThese vehicles are taken on finance leases as disclosed in Note 16.

The depreciation has been included in the following headings-

8. DEFERRED TAX ASSETS/ LIABILITIES (NET)

Deferred taxes arising from temporary differences are summarized as follows:

a) The Group has created deferred tax assets on all 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 recognized in the Consolidated Statement of Comprehensive income

9. INCOME TAX CREDIT

Income tax is based on tax rate 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:

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:

Indus Gas profits are taxable as per the tax laws applicable in Guernsey where zero percent 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. Considering that both Cyprus and Mauritius have double tax avoidance arrangement with 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 till 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. To the extent this expenditure remains unutilized, it can be carried forward indefinitely to subsequent years for set off against future taxable income. During the year ended 31 March 2011, the Group had commenced commercial production and has started to generate profits in Newbury and iServices. Further during the year ended 31 March 2013, the group has increased its operation as result of capitalisation of new production facility (refer to note 7). Accordingly, the Group has started receiving set off of this expenditure against taxable income and management believes there is reasonable certainty of utilisation of remaining unutilized expenditure in the future years. Therefore, deferred tax asset has been created on unutilized balance of these expenditures.

10. INVENTORIES

Inventories comprise of the following:

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. No inventory write downs or reversals are recognized in the years ended 31 March 2013 and 2012.

Consumption of inventories of US$319,667 (previous year: US$ 216,808) were recorded as an expense under the heading 'cost of sales' in the consolidated statement of comprehensive income during the year ended 31 March 2013.

11. OTHER CURRENT ASSETS

Prepayments for procurement of debts represent the proportionate fee paid for the un-utilised facility (refer to Note 14).

12. CASH AND CASH EQUIVALENTS

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 2013 is 182,973,924 (previous year: 182,913,924). During the year ended 31 March 2013, one of the directors has exercised his right of share option and has been issued 60,000 Shares.

--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 on translation of assets and liabilities of Indus Gas into US$ till 30 November 2010 when its functional currency was assessed as GBP. Subsequent to 1 December 2010, functional currency of Indus Gas was reassessed as US$.

Share option reserve

The amount of share option reserve represents the accumulated expense recognized by the company in its profit & loss on account of share based options given by the Company.

Merger reserve

The balance in 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 of entity under common control.

14. LONG TERM DEBT FROM BANKS

The Group obtained two term loan facilities from a consortium of banks in the amount of $110,000,000 and $40,000,000. Against the loan of $110,000,000, Indus Gas has drawn US$ 109,904,073 (previous year US$ 109,904,073) and the balance has lapsed and cannot be utilised. The other loan facility of $ 40,000,000 has been fully utilised as at year end.

Above debt includes a balance US$ 81,530,486 repayable in quarterly instalments of the loan is US$3,939,000 with last instalment falling due in May 2018. This loan bears interest of LIBOR plus 500 basis points payable along with each quarterly instalment.

Balance of US$ 37,645,638 is repayable through quarterly instalments of US$ 400,000 with last instalment falling due in May 2021. This loan bears interest of LIBOR plus 400 basis points payable along with each quarterly instalment.

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

The term loans are secured by all the assets of subsidiaries of Indus i.e. iServices and Newbury in addition to the Group's participating interest in the Block RJ-ON/6 to the extent of SGL field and all future receivables from gas sales.

The fair value of the above variable rate borrowings are considered to approximate their carrying amounts.

15. PROVISION FOR DECOMMISSIONING

As per the PSC, the Group is required to carry out certain decommissioning activities on gas wells. 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.

16. FINANCE LEASE OBLIGATIONS

Finance lease obligations represent leases entered into for vehicles which are used and operated by the Group for the exploration and evaluation activities.

The table below summarises the total liability on account of these finance lease payments:

The finance lease obligations that are payable within the next 5 years from each reported period are as follows:

17. PAYABLE TO RELATED PARTIES

Related parties payable comprise of the following:

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 (hereinafter referred to as "Assignment Agreement").

On 31 March 2013 through an amendment to the Assignment agreement between the Group and Focus, entire outstanding balance of Focus is converted into a short term liability payable on demand. The Group reimburses interest cost incurred by Focus on its borrowings taken from third parties to finance the above mentioned short term borrowing subject to a minimum interest rate of 6.5 per cent per annum and maximum interest rate of 10 per cent per annum. The actualised interest rate for the entire balance is 6.5 per cent for the current year (previous year 6.5 per cent).

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. Out of this loan from Gynia Holdings Ltd., US$ 52 million is subordinated to loans taken from the banks (detailed in note 14) and therefore, is repayable along with related interest subsequent to repayment of bank loans in March 2021. Balance of US$ 54 million is repayable along with related interest in the year ending 31 March 2019.

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

Other payables to related parties comprise of outstanding balances to associate entities and directors and are all short term in nature. The carrying values of the borrowings and other payables are considered to be a reasonable approximation of fair value.

18. EMPLOYEE COST

The Group does not have employees. However, cost 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$ 262,325 (previous year US$ 242,652) and US$ 380,253 (previous year US$ 531,448) respectively.

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

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

20. OPERATING LEASES

Lease payments capitalised under exploration and evaluation assets and development/ production assets during the year ended 31 March 2013 amount to US$ 45,260,114 (previous year:US$35,972,144 ). 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 are cancellable 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.

21. 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", "Advisers 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 total expense recognised in the profit or loss under the heading 'administrative expenses' of the year ended 31 March 2013 is NIL (previous year: US$ 12,188).

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.

The following principal assumptions were used in the valuation: Expected volatility was determined by comparison with implied volatility of Oil and Gas sector stocks and trading volatility of the Company available till the grant date. Dividend yield is taken as nil as the Group has not paid any dividend. The risk-free rate is the rate associated with a risk-free security with the same maturity as the option. At each reporting date, the Group reviews its estimates of the number of options that are expected to vest. The Group recognizes the impact of the revision to original estimates, if any, in the profit or loss, with a corresponding adjustment to 'stock option reserve' in equity.

The inputs to the Black Scholes model for options that have been granted are summarised as follows:

A Consequent to a modification made subsequent to the current year, the option life for advisors has been changed to 6 years.

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 2013, one of the directors has exercised his right of share option for 60,000 Shares. The outstanding balance and exercisable share options granted to directors and consultants for the year ended 31 March 2013 were 180,000 having a weighted average price of US$ 1.64 per option (previous year: 240,000 with weighted average price of US$ 1.64 per option) and expiry date of 6 June 2013. Subsequent to 31 March 2013 all the options have been exercised by the option holders. However based upon the request of these holders, the payment has been deferred till the date of sale of such option shares and interest at 6% per annum shall be levied from the date of notice of exercise till the exercise value is finally remitted to the Company. Issue of shares for such options is in process.

Share options granted to Arden Partners

There was no movement in the outstanding options under this category during the year ended 31 March 2013 as the Share options granted to advisors 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 advisors for the year ended 31 March 2013 were 76,220 having a weighted average price of US$ 1.64 per option (previous year: 76,220 with weighted average price of US$ 1.64 per option). In the previous year upon the request of Advisor, the validity of exercise period was extended by two years to expire on 6 June 2013. Subsequently on 10 June 2013 the validity of the exercise period has been further extended by one year and now the options will expire on 6 June 2014.

The share options outstanding at the end of the year had a weighted average remaining contractual life of 1.18 years (previous year: 1.18 years).

22. 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 for the year ending 31 March 2013 and 31 March 2012 are as follows:

As detailed in note 21 above on Share based payments, the Group has granted options as under:

· Share options granted to Directors and Advisors- 180,000 Outstanding exercisable options (previous year- 240,000)

· Share options granted to Arden Partner- 76,220 Outstanding exercisable options (previous year- 76,220)

23. RELATED PARTY TRANSACTIONS

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

Disclosure of transactions between the Group and related parties and the outstanding balances as of 31 March 2013 and 31 March 2012 is as under:

Transactions with parent company

Transactions with KMP and entity over which KMP exercise control

*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 9.

24. SEGMENT REPORTING

The Chief Operating Decision Maker (or Chief Executive Officer) reviews the business as one operating segment being the extraction and production of oil and 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$ 336,021,358 (previous year: US$ 253,405,921).

The Group has a single product, i.e. natural gas, which is supplied to a single customer, GAIL within India.

25. COMMITMENTS AND CONTINGENCIES

The group has no contingencies as at 31 March 2013 (previous year Nil).

A summary of the commitments existing as at 31 March 2013 and 31 March 2012 are as follows:

26. ACCOUNTING ESTIMATES AND JUDGEMENTS

In preparing consolidated financial statements, 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 statement 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 management's view each of the individual entity's functional currency reflects the transactions, events and conditions under which the entity conducts its business. Management believes that US$ represents 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 is tested for impairment prior to reclassification into development assets on successful discovery of gas reserves.

Impairment of tangible and intangible assets

The Group follows the guidance of IAS 36 and IFRS 6 to determine when a tangible or an intangible 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 and intangible assets. Upon the confirmation of commercial discovery in the SSF field in the Block on 3 December 2012, as detailed in note 6, management has carried impairment assessment of property, plant and equipment and intangible assets of the Block. Further management has assessed that no such indicators have occurred or exists as at 31 March 2013 to require another impairment testing of property, plant and equipment and intangible assets on that date. Management considers entire Block as one Cash generating unit for the purpose of impairment testing.

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 balance 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 and intangible assets of the Block on 3 December 2012 upon the confirmation of commercial discovery in the SSF field in the Block. 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 on the basis of gas reserves confirmed by an independent expert. Selling price of the gas is based on existing selling price to GAIL which is fixed for three years and thereafter with 3% per annum increase for future years. 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, plant and equipment and intangible assets of the Block.

27. BASIS OF GOING CONCERN ASSUMPTION

The Group has current liabilities amounting to US $ 77,948,038 majority of which is towards current portion of borrowings from banks and related parties summarised in notes 14 and 17. As at 31 March 2013, the amounts due for repayment within the next 12 months to banks are US$ 16,962,446 which the Group expects to meet from its internal generation of cash from operations. Also during the year, as a result of the commencement of the additional production facilities, as summarised in note 7 on Property, Plant and Equipment, the expected inflows from the annual take and pay as per the contract with the key customer shall be increased significantly in the coming year. In furtherance of the subordination of the loan as detailed in note 17, Gynia has also assured the Group to provide support for any cash requirement to meet its obligations towards banks not met through internal generation of cash. Further, as detailed in note 6, management intends to file an integrated development plan for all identified and commercially feasible gas reserves in the coming year to the management committee. Once they are approved, the Company's ability to raise borrowings to fund development expenditure will be further enhanced. Based on this, the consolidated financial statements have been prepared on a 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 to shareholders and benefits to 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 total debt divided by total capital employed.

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

The gearing ratio has increased since the previous year due to increase in the drawdown of loans from banks and related parties to fund additional exploration, evaluation and development activities of 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 as recognised at the date of the statement of financial position of the reporting periods under review may also be categorised as follows:

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$. All revenues from gas sales will be received in US$ 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 2013 and 31 March 2012 is as follows:

The Group's currency exposure risk towards Indian Rupee is negligible due to the insignificant currency balance exposed to such risk. Also, the Group doesn't maintain significant cash balance in GBP. The balance as at 31 March 2013 largely represents funds received from Gynia Holdings Ltd on 28 March 2013 which are remitted to Focus on 2 April 2013. Therefore, the Group believes its exposure towards GBP is negligible.

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 summarises the maturity profile of the Group's financial liabilities based on contractual undiscounted payments for the liquidity analysis

Interest rate risk

The Group's policy is to minimise interest rate risk exposures on long-term financing. Interest rate on short term borrowing from Focus is linked to actual interest incurred by Focus capped between 6.5 percent and 10 percent. The Group is also exposed to changes in market interest rates through bank borrowings at variable interest rates. Short term investments of the Group are also at fixed interest rate and therefore, don't expose the Group to risk from changes in interest rate.

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, management estimates a range of 50 basis points to be an approximate basis for the reasonably possible change in interest rates. All other variables are held constant.

Since the loans are taken primarily for the purpose of exploration and evaluation and development and production activities, majority of the borrowing costs are capitalised to the cost of the asset. Hence, changes in the interest rates do not have any immediate substantial impact on the profit or loss.

Commodity price risks

The Group's share of production of gas from the Blockis sold to GAIL. The price has been agreed for the current period and for the next three years and 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 the credit risk to be significant. Other receivables such as security deposits and advances with related parties do not comprise 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 this to be significant. None of the financial assets held by the Group are past due.

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