ANNUAL
REPORT
w w w . i n d u s g a s . c o m
2014-15 ANNUAL REPORT 2013-14
Highlights
Chairman's Statement
Chief Executive's Review
Board and Executive Management
Directors' Report
Corporate Governance
Overview
Corporate Governance
Financial Statements
Independent Auditors' Report 
Consolidated Statement of Financial Position
Consolidated Statement of Comprehensive Income
Consolidated Statement of Changes in Equity
Consolidated Statement of Cash Flows
Notes to Consolidated Financial Statements
02
03
04
10
11
14
17
19
21
22
23
24
CONTENTS
ANNUAL REPORT 2014–15
CONTENTS
Overview
02 Highlights
03 Chairman’s Statement
04 Chief Executive’s Review
Corporate Governance
11 Board and Executive Management 
12 Directors’ Report 
15 Risk and Risk Management
17 Corporate Governance
Financial Statements
20 Independent Auditor’s Report
22 Consolidated Statement of Financial Position
24 Consolidated Statement of Comprehensive Income 
25 Consolidated Statement of Changes in Equity 
26 Consolidated Statement of Cash Flow 
27 Notes to Consolidated Financial Statements ANNUAL REPORT 2014–15
1
OvErviE w
Indus Gas Limited (“Indus”) is focused on oil and gas exploration and development in Rajasthan, India, 
in Block RJ-ON/6. Indus owns a 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 2,176 km² (post Declaration of Commerciality (DoC)) 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 published by LR Senergy (GB) 
Limited (referred as “Senergy”) in December 2014 the 2P recoverable reserves, 2C contingent resources 
& best estimate prospective resources in the block are 6.095 tcf (trillion cubic feet) of gas. ANNUAL REPORT 2014–15
2
HiGHliGHTS
•	
Completed full year of production at enhanced capacity of 42 mmcf/d (33.5 mmcf/d net of CO
2
) 
from SGL Field. Company is on track to increase gas production further in years ahead. 
•	
Approval of Declaration of Commerciality (“DOC”) during the year for a ~2000 km
2
 non SGL area to 
be retained as potential mining lease area (in addition to 176 km
2
 of SGL Mining lease). An integrated 
Field Development Plan for this Non SGL Area is currently under preparation for submission on or 
before February 2016. The remaining Block area stands relinquished in line with PSC requirements.
•	
Published new Competent Persons Report (CPR) delivering a significant uplift in the Company’s 
reserves (Gross 2P/2C of 4,091 bcf in 2014 vs Gross 2P/2C of 3,272 bcf in 2012). This is the Company’s 
fourth CPR which has sequentially increased the hydrocarbon potential of the Block.
•	
Successfully drilled a large number of appraisal wells with encouraging gas shows, which will help 
the Company put together a robust integrated field development plan for the Block area outside 
of SGL. 
•	
A new gas sand system (called P9) was successfully tested for production for the first time below 
producing zone P10 in Pariwar formation in SGL Field. 
•	
Ongoing discussions with counterparties to establish connection to cross country pipeline to Western 
states of Gujarat and North-West Pipeline Grid to enable long term gas monetisation.
OPERATIONAL (CUMULATIVE AS AT 31 MARCH 2015)
•	
Acquired, processed and interpreted 2019.05 Square km of 3D seismic data as at 31 March 2015. 
This includes 106 square km of High Density 3D Seismic.
•	
Acquired, processed and interpreted 1037.28 line km of 2D seismic data. 
•	
During the year 15 new wells including 5 appraisal wells and 10 development wells averaging a 
depth of 3,100 meters per well. 
FINANCIAL 
•	
Reported consolidated revenues, operating profits & profit before tax of respectively US$ 41.39 mn, 
US$ 30.02 mn & US$ 30.00 mn for the year excluding “ToP” amount. Comparatively, in FY2013–14  
reported consolidated revenues, operating profit and profit before tax were respectively 
US$ 27.83 mn, US$ 20.93 mn & US$ 21.01 mn.
•	
Adjusted consolidated revenues, operating profit and profit before tax of respectively US$ 42.34 
million (mn), US$ 30.97 mn & US$ 30.95 mn (after considering and including a management 
adjustment for “Take or Pay” (ToP, under the GAIL contract, see Summary of Accounting Policies 
section 5.4 Revenue Recognition) receipts of US$ 0.95 mn for the year). Comparatively, in FY2013–14  
adjusted consolidated revenues, operating profit and profit before tax were respectively 
US$ 43.43 mn, US$ 36.53 mn & US$ 36.60 mn after considering and including a management 
adjustment for “ToP” receipts of US$ 15.60 mn for the year. 
•	
Total gross investment of US$ 84.39 mn during the year (US$ 77.1 mn in FY2013–14) in respect of 
appraisal and development of the Block. 
•	
The Company concluded and has drawn down on an incremental term loan facility of US$ 180 mn 
from a syndicate of existing lenders as well as new lenders on competitive terms. Out of US$ 180 mn, 
company had drawn down US$ 135.6 mn by 31 March 2015 and remaining amount has been fully 
drawn post 31 March 2015. The facility, maturing in 2024, will be used to meet the cash call liabilities 
as well as ongoing investment in the Block. All repayments under the existing debts were made on 
a timely basis.
•	
The Company successfully widened available funding options by accessing a new financial market 
with the creation of a Singapore listed Medium Term Note (MTN) programme of USD 300 million. 
After the end of financial year, Indus has issued a first tranche of SGD 100 million senior unsecured 
notes due 23 April 2018 at a coupon of 8%.  ANNUAL REPORT 2014–15
3
CHairmaN ’S STaTEmENT
This has been an extremely challenging period for the global oil and gas sector. Whilst the Indus Gas 
share price has not escaped the industry wide malaise, the Company’s fundamentals have remained 
robust and several key milestones have been achieved during the financial year under review. 
The Company’s operational and financial performance has been strong with consistent revenues and 
profits generated during the period. The Company has also successfully secured additional balance 
sheet capacity, on very attractive terms, from which to fund future production growth and infrastructure 
investment.
The approval of the Declaration of Commerciality, granted in September 2014, marked the culmination 
of over a decade of intensive exploration and planning work on the block. It paves the way for the 
integrated development of our already significant, and growing, reserves base.
In 2014, Indus released its fourth Competent Person’s Report. This delivered a 52% uplift in the Company’s 
gross 2P reserves and an 11% increase in the 2C contingent resources base compared with the last CPR 
which was published in 2012. These impressive growth rates highlight the continued successful execution 
of the Company’s appraisal and drilling programme. 
On-site exploration, appraisal and testing activity has continued at an impressive pace during the year 
with details outlined in the Chief Executive’s Review. 
The Board would like to thank employees, shareholders and all other stakeholders for their loyalty. 
Against a difficult current backdrop for global oil and gas prices, management will continue to focus on 
the execution of the Company’s long-term strategy of achieving both growth in reserves and commercial 
production. The Indian economy continues to suffer from a shortage of domestically sourced energy 
production and Indus remains well placed to help address this deficit.
Peter Cockburn
Chairman
21 September 2015 ANNUAL REPORT 2014–15
4
CHiEF ExECuTivE ’S r EviE w
I am pleased to announce another year of gas sales based on gas production capacity of 42 MMscfd 
(33.5 MMscfd net of CO
2
) achieving consolidated reported revenues of US$ 41.39 mn and adjusted 
revenues (including “ToP” receipts) of US$ 42.34 mn. We have continued to build scale in our production 
profile and our stated long term business plan remains on track. We continue to achieve this while 
maintaining compliance with the terms of our Production Sharing Contract, applicable laws and sound 
standards of health and safety. The approval of the DOC has opened the way to the establishment of an 
integrated Field Development Plan for the non SGL area of the Block. Our new CPR demonstrated our 
ability to convert resources into reserves and enhance the future revenues of the Block. We have also 
continued with our appraisal program and have completed significant drilling and testing, confirming 
and establishing further gas presence. 
DECLARATION OF COMMERCIALITY
The Declaration of Commerciality (DOC) for a circa 2000 km
2
 non SGL area of the Block (DOC Area) 
was approved by the Director-General Hydrocarbons (DGH) on the 18 September 2014 and by the full 
Block Management Committee on the 20 October 2014. The DOC is another important step in the 
history of the Block as it recognises the commercial feasibility of the development of a large acreage in 
the Block. The DOC area along with the 176 km² SGL Development Area are our chosen areas for future 
development work with the balance of block being relinquished.
The DOC has allowed work to begin on a Field Development Plan (FDP) for the area and this is expected 
to be completed under the usual process on or before February 2016 as required under the PSC. 
Approval of the FDP will pave the way for the grant of mining lease over the DOC area. 
COMPETENT PERSONS REPORT (CPR)
In December 2014 we announced the results of our latest CPR from Senergy The significant uplift in the 
Company’s reserves and growth in Contingent Resources (shown below) reflects the major operational 
progress made on Block RJ-ON/6 since the last CPR was conducted in 2012. This is the third CPR 
completed by Senergy with substantially the same team members thereby building a continuity of 
analysis.
CPR Highlights
•	
Gross ‘Proven plus Probable’ remaining reserves increased to 872 billion cubic feet (“bcf”) (Net of 
18 bcf already produced as of 30 September 2014)
52% increase from 573 bcf assigned in previous CPR by Senergy in 2012
Proven reserves increased to 423 bcf as against 118 bcf assigned in previous CPR by Senergy 
in 2012
New reserves largely attributed to new sands (lower P10) within SGL field and SSM fields
Discounted cash flows at 10% IRR (NPV10) in respect of “Proven plus Probable” reserves of 
872 bcf estimated to be US$ 2,309 mn (before capital expenses) and US$ 1,785 mn (Net of 
capital expenses). 
•	
2C gross contingent resources increased 19% from 2,699 bcf to 3,219 bcf - Current CPR utilizes 
only some of the recent data used in the approval of the Declaration of Commerciality in respect of 
contingent resources.
•	
Best estimate prospective resources of over 2 tcf attributable to the wells outside the SGL 
development area
•	
Pipeline connection to existing cross country pipeline and western gas grids emerging as a viable 
option for long term gas monetization. ANNUAL REPORT 2014–15
5
Summary table
The table below provides a summary of the changes in reserves and resources from the report provided 
by Senergy in 2012 to the current updated report by Senergy:
Category
Senergy 2014¹ Senergy 2012
Gross 
(bcf)
Net to Indus 
(bcf)
Gross 
(bcf)
Net to Indus 
(bcf)
2P Reserves 872 672 573 449
2C Contingent Resources 3,219 2,897 2,699 2,429
Best Estimates Prospective Resource 2,004 1,804 2,182 1,964
Note 1: Senergy current reported numbers are net of 18 bcf of gas already produced as of 30 September 2014.
The table below provides a summary of current updated report by Senergy broken into different 
classifications for Gross Volumes:
Total Gas Volumes as per Senergy Report 2014 (bcf)
Classification 1P 2P 3P
Reserves* 423 872 1,643
Classification 1C 2C 3C
Contingent Resources 991 3,219 6,698
Classification Low Estimates Best Estimates High Estimates
Prospective Resource (Unrisked) 542 2,004 4,562
* Senergy current reported numbers are net of 18 bcf of gas already produced as of 30 September 2014.
This report has been completed in accordance with the 2007 Petroleum Resources Management System 
prepared by the Oil and Gas Reserves Committee of the Society of Petroleum Engineers (SPE) and 
reviewed and jointly sponsored by the World Petroleum Council (WPC), the American Association of 
Petroleum Geologists (AAPG) and the Society of Petroleum Evaluation Engineers (SPEE). Details of the 
2007 Petroleum Resources Management System together with definitions and glossary can be found at:
http://www.spe.org/industry/docs/Petroleum_Resources_Management_System_2007.pdf
The Company has continued drilling a number of appraisal and development wells during the year. 
A summary of cumulative seismic/drilling as at 31 March 2015 is as follows:
•	
2019.05 Square km of 3D seismic data. This includes 106 square km of High Density 3D seismic 
acquired in SGL Field.
•	
1037.28 line km of 2D seismic data. 
•	
15 new wells drilled averaging 3,100 meters per well.
A summary of activities since April 2014 is provided below:
SGL Field Development
During the year, a total quantity of 12,902 MMscf of gas (2014: 8,085 mmscf) was produced from the 
field out of which 9,781 MMscf (net of CO
2
) was supplied to GAIL, which is a significant increase over  
the 6,691 MMscf supplied in the previous financial year. The operations at Rajasthan Rajya Vidyut 
Utpadan Nigam Limited (RRVUNL), the State Electricity Company in Rajasthan, have improved during 
the year resulting in increased gas off take in the second half of the year. The operations have now largely 
stabilized and GAIL expects to reach the gas offtake target as per signed GSPA on a long term basis, 
without needing to make “Take or Pay” payments. There were no major breakdowns during the year and 
GAIL met its obligations under the ‘Take or Pay (ToP)’ agreement. Invoiced revenues increased by 49%  ANNUAL REPORT 2014–15
6
from the previous year as the power plant progressed towards normalized operations. The contribution 
under the “ToP” obligation was for US$ 0.95 mn, a significant decrease over the previous year due to the 
enhanced installed sales capacity of 33.5 MMscf/d being available for the full financial year.
Activities to support additional sales to GAIL have made good progress. Additional successful production 
wells have been completed and tied into the gas gathering system. Treatment and processing plants are 
in place. 
Drilling, Seismic, Completion Operations
Operational activities over the last year have largely followed the Group’s various objectives:
a) appraisal drilling to support the DOC application and integrated field development plans;
b) drilling and completion of production wells for the SGL Field Development continued as planned to 
meet contracted and planned gas sale requirements;
c) testing various wells previously drilled, where gas shows were encountered to enable the Group to 
increase its reserve base; and
d) testing the tight gas recovery potential in addition to conventional gas discovered in the Pariwar 
formation.
During the year, Indus has been acquiring, in phases, new seismic data giving more clarity on the Block 
potential and providing additional drilling prospects. The current drilling programme is progressing on 
schedule and producing positive results. We continue to test concepts and obtain log and core data for 
analysis outside the SGL area. In the SGL area work continues to expand the knowledge of the producing 
intervals. Additional testing is part of a programme to enhance production and maximize recovery of 
gas through good asset management. Activities such as this will increase as we obtain and act on new 
data and production history. An important development in respect of SGL Field was discovery of a new 
sand system called P9 or lower P10 sands, located just below the existing producing upper P10 sands in 
Pariwar formation. This new sand system was successfully tested for production and going forward will 
likely add to the reserves and production from existing as well as new wells.
The details of the wells, which were drilled during the year, are as follows:
Development wells
New Development/production wells drilled during the year included the following:
SGL-SB1 – 3277m Gas Producer (Pariwar Formation)
The SGL-SB1 well was drilled to the base of the Pariwar P10 reservoir zone at 3277m on the southern 
flank of the main SGL Field structural closure area. The well was completed with a barefoot completion 
with an open hole interval of 207 metres (from 3070–3277m) covering the entire P10 and P20 Pariwar 
Reservoir Zones and is currently on production. Initial pressure transient and deliverability tests achieved 
flow rates of 1.03 MMscf/d on a 6mm choke to 5.07 MMscf/d on a 10mm choke for this well.
SGL-15 – 3286m Gas Producer (Pariwar Formation)
Well SGL-15 terminated at 3286 metres within the Pariwar Formation to allow full evaluation of the P10 
and P20 Reservoir zones. The well is situated to the east of the main SGL Field structural closure area 
within the same fault compartment previously targeted by wells SSF-3 and SGL-P2. The well is currently 
perforated and completed for production from the P20 reservoir zone over the interval 3023–3032m with 
flow rates ranging from 1.87 MMscf/d on an 8mm choke to 2.06 MMscf/d on a 12mm choke achieved 
during pressure transient and deliverability testing. ANNUAL REPORT 2014–15
7
SGL-16 (SGL SB-2) – 3196m Gas Producer (Pariwar Formation)
Well SGL-16 reached a total depth of 3196m which corresponded to the base of the Pariwar P10 
Reservoir Zone. It is located within a crestal position within the main SGL Field structural closure area. 
The well was cased with the interval 3111–3117m (Uppermost P10 Zone) perforated and completed for 
production with a flow rate of 4.48 MMscf/d recorded on an 8mm choke (and 6.51 MMscf/d on a 10mm 
choke) during pressure transient and deliverability testing.
SGL-SB3 – 3344m Gas Producer (Pariwar Formation)
Well SGL-SB3 was drilled as an SGL field development well within a discrete fault compartment on the 
western flank of the SGL Field structure, which had previously also been targeted by well SGL-D2. The 
SGL-SB3 well encountered key gas shows within sands in the upper part of the Pariwar P10 reservoir 
zone, which correlated directly with sands that were currently on production in the other nearby SGL 
Field wells. Crucially, SGL-SB3 also encountered gas-bearing sands in the lower part of the P10 reservoir 
zone interval that were not on production in any other well at that time in the SGL Field area. The well 
was cased and completed for production from a 10 metre perforation zone from the lower P10 reservoir 
sands (3282–3292m measured depth). This interval is currently on production from this new additional 
producing zone discovered in the well. Additional gas-bearing upper P10 sands are currently behind 
casing with future additional development potential.
SGL-18 – 3325m Gas Producer (Pariwar Formation)
The SGL-18 SGL Field development well was drilled on the western flank of the same structural fault 
compartment as the previous SGL-SB3 well. It was drilled in a down-dip position on the structure relative 
to SGL-SB3 in order to test the extent of the lower P10 gas bearing sands as encountered in that 
well. The SGL-18 well encountered key gas shows in the upper parts of the P10 reservoir zone. It also 
encountered key gas sands in the lower P10 zone as seen in SGL-SB3. The well was cased and completed 
for production from a 12 metre perforation within the lower P10 reservoir zone sand interval from 3258–
3270m (measured depth), with the upper P10 zone gas sands currently behind casing allowing future 
additional development potential. The well is currently on production from the lower P10 sand zone.
SGL-19 – 3299m Gas Producer (Pariwar Formation)
Well SGL-19 was drilled as an infill SGL Field development well on the main SGL Field structural 
compartment which was previously drilled by nearby wells SGL-1, SGL-6 and SGL-7. Production taken 
to date from this structural compartment had been from the upper P10 zone reservoir sands only at the 
time of drilling. The SGL-19 well encountered key gas shows in both the upper and lower P10 reservoir 
sand zones and was subsequently cased and completed for production from a 9 metre zone (3243.5–
3252.5m measured depth) in the lower P10 target sands. The well was placed on production from the 
lower P10 sands from the same zone as wells SGL-SB3 and SGL-18. Additional upper P10 reservoir sands 
are currently behind casing with potential for future additional development. 
SGL-20 – 3411m Development well (Pariwar Formation)
The SGL-20 development well was drilled on the southern flank of the SGL Field in a down-dip location. 
The well encountered gas shows in the Pariwar P20 reservoir sands and within the upper part of the P10 
Pariwar reservoir zone. The well has been cased but has not been completed for production to-date.
SGL-21 – 3357.6m Gas Producer (Pariwar Formation)
Well SGL-21 was drilled as a development well on the northern flank of the main SGL Field structural 
closure area. The well encountered key gas shows within the upper P10 Pariwar reservoir zone. It was 
cased and completed for production from a 3 metre perforation (3208–3211m measured depth) from the 
uppermost sands of the P10 reservoir zone. The well is currently on production from this zone. ANNUAL REPORT 2014–15
8
SGL-23 – 3409m Gas Producer (Pariwar Formation)
The SGL-23 development well is located on the crestal part of the western SGL Field structural closure 
area that was also drilled by SGL-SB3 and SGL-18. The well encountered key gas shows in the upper and 
lower target intervals of the Pariwar P10 reservoir zone. It was cased and completed for production from 
a 12 metre perforation zone (3318–3330m measured depth) from key lower P10 zone reservoir sands. 
The well is currently on production (since March 2015).
SGL-28 – 3270m Development well (Pariwar Formation)
The SGL-28 development well is located close to the crestal part of the western SGL Field structural 
closure area that was also drilled by SGL-SB3, SGL-18 and SGL-23. The well encountered key gas shows 
in the upper and lower target intervals of the Pariwar P10 reservoir zone. It was cased and completed 
for production testing from a 12 metre perforation zone (3250–3262m measured depth) from key lower 
P10 zone reservoir sands. The well is currently undergoing testing and preparation to be placed on 
production at the time of writing.
Appraisal Wells
During the year , the Company has completed the following appraisal wells and has encountered gas shows 
in the majority of these wells. Most of these wells are in testing stages and are critical in establishing our 
right to retain the maximum area in the Block in line with the DOC application and establishing additional 
reserves and resources. Since many of these wells have multi-zone gas shows, the Company is evaluating 
an optimum strategy for multi-zone testing and completion (having previously gathered favourable data 
sufficient for the DOC application). 
The description of some of the appraisal wells completed in the year is as follows:
A-11-7N – 3378.3m Appraisal well with gas shows (Pariwar Formation)
Well A-11-7N was drilled in order to appraise the same structural closure area as older well SSM-1, which 
encountered gas shows at the Pariwar reservoir levels but had to be abandoned prior to wireline logging 
and testing due to hole complications. A-11-7N encountered gas shows within Pariwar P20 and P10 zone 
sands at multiple levels. The well was cased and one zone selected for testing from the main P10 (upper) 
reservoir zone from a 4.5 metre perforation interval (3224–3228.5m). To-date this zone has failed to flow 
gas to surface at commercial rates and the well is suspended pending further review.
S-EPN-1 – 3489m Appraisal well with minor gas shows (Pariwar Formation)
Well S-EPN-1 was drilled in very close proximity to a major fault trend with the aim to assess whether 
natural fractures associated with faulting would enhance reservoir productivity. The well terminated 
within the upper parts of the Pariwar P10 reservoir zone and only minor elevated gas readings were 
observed whilst drilling. The well was subsequently abandoned and no further testing was carried out at 
this location. 
SX-7 – 4581m Appraisal well with gas (Pariwar and B&B Formations)
Well SX-7 targeted a discrete fault compartment in the western area of RJ-ON/6 for appraisal of Pariwar 
and B&B Formation reservoir targets in this area. The well encountered elevated gas shows within the 
Pariwar P20 and P10 reservoir zones and drilled on to the deeper B&B Formation targets. Gas shows 
were then encountered in upper B&B Formation target sands, with major shows encountered whilst 
drilling the main Lower B&B target zone. Core was taken from key reservoir target zones and the well is 
currently undergoing detailed petrophysical, geological and geomechanical analysis in order to assess 
how best to proceed with further testing of the key gas-bearing reservoir targets encountered in this 
well. ANNUAL REPORT 2014–15
9
S-97S – 132m Appraisal well with gas (Pariwar and B&B Formations)
The aim of the S-97S Appraisal well was to assess a major structural closure in the western part of  
RJ-ON/6 which had been previously drilled by well S-97. The S-97S well encountered significant gas 
shows in the Pariwar P20 and P10 reservoir zones and within target sands within the upper parts of the 
B&B Formation. The Lower B&B sands were not penetrated by this well. The well was cased and 4 upper 
B&B sand zones were selected for initial perforation and testing, covering the intervals 3937–3940m, 
3948–3951m, 3958–3961m and 3980–3989m. Testing and assessment of this well is ongoing at the time 
of writing.
EPN-2 – 1651m Gas Producer (Pariwar Formation)
Well EPN-2 was drilled in order to appraise the structural closure area in the western part of RJ-ON/6 
previously successfully tested for gas (from the Pariwar Formation) by well EPN-1. Furthermore, B&B 
Formation reservoir zones were also targeted by EPN-2 which were not penetrated by EPN-1. The well 
encountered key gas shows in the Pariwar P20 and P10 reservoir zones and within upper and lower B&B 
target zones. Cores were taken from key reservoir intervals and (at the time of writing) the well is currently 
undergoing detailed petrophysical, geological and geomechanical analysis in order to assess how best to 
proceed with further testing of the key gas-bearing reservoir targets encountered in this well.
Seismic
We have 3D seismic coverage of 2019.05 square km area as of 31 March 2015. This includes 106 square 
km of high density 3D seismic acquired in SGL Field area. We have 89% of 3D Seismic coverage of the 
2,000 Square km DOC area and currently work is ongoing to complete the seismic data set to cover the 
entire 2000 km
2
 DOC area.
Financials
During the financial year , the Company supplied 9781 MMscf of gas and invoiced revenues of US$  41.39  mn 
(2013/14 US$ 27.83 mn), resulting in reported operating profit of US$ 30.02 mn (2013/14 US$ 20.93 mn). 
The reported profit after tax was US$ 16.24 mn (2013/14 US$ 11.77 mn) after a foreign exchange loss of 
US$ 0.02 mn. Indus additionally received take or pay payments of US$ 0.95 mn for the period, which are 
considered as deferred revenues and shown as liabilities since these receipts can potentially be set off 
against future gas supplies to GAIL, provided such supplies are over and above 90% of the contracted 
quantities, subject to certain restrictions as to the period in which such offset can be made. An amount 
of US$ 5.08 mn is disclosed as current liabilities and the remaining US$ 25.56 mn is disclosed as non-
current liabilities. Current liabilities include the maximum amount for which the Company is obliged to 
supply gas against the “ToP” amount received, in the next twelve months. The Company is not obliged 
to supply gas over and above 100% of the contracted quantities in any given period. In the event, 
the set-off terms are not complied with, the Company has no further obligation to return back “ToP” 
amounts. Since the amount of “ToP” invoiced is non-refundable, the management considers this amount 
as a revenue and profit adjustment and accordingly adjusted consolidated revenues, operating profit and 
profit before tax for the year were respectively US$ 42.34 mn, US$ 30.97 mn and US$ 30.95 mn after 
including “ToP” amount of US$ 0.95 mn.
While the Company is not expected to pay any significant taxes on its income for many years in view 
of the 100% deduction allowed under Indian Income Tax Act on the capital expenses in the Block, the 
Company has accrued a non-cash deferred tax liability of US$ 13.76 mn as per IFRS requirements.
Post this deferred tax liability provision, the net profit for the year was US$ 16.24 mn.
The expenditure on exploration and evaluation assets during the year was US$ 34.02 mn. In addition 
during the year subsequent to the discovery of gas reported to regulatory authorities, an amount of 
US$ 34.02 mn has been transferred from exploration and appraisal assets to development assets. The 
value of development assets and production assets has increased to US$ 491.34 mn. The development 
assets amortised on the gas produced during the year was US$ 7.58 mn. ANNUAL REPORT 2014–15
10
The current assets (excluding cash) as of 31 March 2015 stood at US$ 11.88 mn, which includes 
US$ 5.23 mn of inventories and US$ 5.33 mn of trade receivables. The trade receivables are mainly on 
account of fortnightly receivables from GAIL billed on the last day of the year. The current liabilities of 
the Company, excluding the related party liability of US$ 23.49 mn and current portion of long term debt 
of US$ 18.39 mn, stood at US$ 5.24 mn. This comprised mainly of deferred revenue of US$ 5.08 mn and 
other liabilities of US$ 0.2 mn.
As of 31 March 2015, the outstanding term loan of the Company was US$ 218.68 mn, out of which 
US$ 18.39 mn was categorised as repayable within a year and the remaining US$ 200.29 mn has been 
categorised as a long term liability. During the year, the Company has received proceeds of US$  131.50  mn 
from incremental term loan facility net of expenses and repaid an amount of US$ 17.32 mm of the 
outstanding term loan facilities, as per the scheduled repayment plan. 
Outlook
During the next twelve months, we expect a further step change in the growth of the Company. Following 
DOC approval we shall look to develop the significant potential of the Block beyond our existing SGL 
Development Area. Strong progress has been made on the preparation of additional gas gathering 
and processing facilities. A cumulative gas processing capacity of 130 MMscf/d is being planned to 
be available by 2016 end to provide a strong platform from which to negotiate further new gas supply 
contracts. We look forward to continued drilling success in both Pariwar and B&B. Negotiations on 
the new gas sales contract with GAIL for offtake by the power plant in January 2017 are ongoing. The 
Company is also progressing the dialogue for the review of gas pricing under our existing sales contract. 
Ajay Kalsi
Chief Executive Officer
21 September 2015 ANNUAL REPORT 2014–15
11
BOard aNd ExECuTivE maNa GEmENT 
PETER COCKBURN (44) – CHAIRMAN & NON-EXECUTIVE DIRECTOR
Mr. Cockburn is a Partner in Clear Peak Capital LLP based in Edinburgh. He was Investment Director at 
Scottish Widows Investment Partnership from 2003 to 2009 and then Head of UK Equities until May 2012. 
Prior to that, he was Investment Manager (UK Equities) at Edinburgh Fund Mangers PLC from 1998 to 
2003. Peter also worked in Audit at KPMG from 1993–98. 
Peter holds a BA in Accountancy, and an MSc in Investment Analysis. He is a member of the Institute of 
Chartered Accountants of Scotland (1997) and the UK Society of Investment Professionals (2000) and 
holds the Investment Management Certificate (1999).
AJAY KALSI (54) – CHIEF EXECUTIVE OFFICER & DIRECTOR
Mr. Kalsi is a successful businessman from India who has established and built a portfolio of companies in 
a range of business sectors including oil and gas, footwear, real estate and business process outsourcing. 
He has international business experience, which includes oil and gas industry operating experience with 
oil and gas assets in India (both onshore and offshore). He holds an M. Phil in Economics from Cambridge 
University and a BSc (Economics) from the London School of Economics. 
JOHN SCOTT (57) – CHIEF FINANCIAL OFFICER & DIRECTOR
Mr. Scott entered the oil industry in 1980 with the British National Oil Corporation and worked in a 
variety of technical and commercial roles. Following an MBA at London Business School, he joined the 
Energy Group of Citibank and subsequently gained corporate finance experience at ABN Amro and 
Standard Bank. Mr. Scott returned to the industry with Halliburton in a senior financial role and has been 
Finance Director of the Toronto Venture Stock Exchange listed Exile Resources Inc. 
BRUCE McNAUGHT (54) – NON-EXECUTIVE DIRECTOR 
Mr. McNaught is a Fellow of the Institute of Chartered Accountants in England and Wales and has worked 
in offshore finance for 30 years with particularly experience of the hydrocarbon sector. He is the Managing 
Director of Chamberlain Heritage Services Ltd., a privately held fiduciary providing professional trust and 
corporate services to clients worldwide. Chamberlain is based in Guernsey and licensed and regulated by 
the Guernsey Financial Services Commission. He was previously Deputy Managing Director of Hansard 
Limited, a similarly licensed Guernsey fiduciary services company. Bruce is the Director of Finance of TSX 
Venture listed Oyster Oil and Gas Limited. ANNUAL REPORT 2014–15
12
d irECTOrS ’ r EpOrT
The Directors present their report and the financial statements of Indus Gas Limited (“the Company”) 
and its subsidiaries, iServices Investments Ltd and Newbury Oil Co. Ltd (collectively the “Group”), which 
covers the year from 1 April 2014 to 31 March 2015.
PRINCIPAL ACTIVITY AND REVIEW OF THE BUSINESS
The principal activity of the Company is that of oil and gas exploration, development and production in 
India.
RESULTS AND DIVIDENDS
The trading results for the year and the Group’s financial position at the end of the year are shown 
in the attached financial statements. The Directors have not recommended a dividend for the year.  
(FY 2013–14: £nil).
REVIEW OF BUSINESS AND FUTURE DEVELOPMENTS
A review of the business and likely future developments of the Company are contained in the Chairman’s 
statement and the CEO’s review, given above.
DIRECTORS REMUNERATION
The Directors’ remuneration for the year ended 31 March 2015 was:
Remuneration (£) Remuneration (US$)
Ajay Kalsi 132,344 196,240
John Scott 200,000 320,592
Peter Cockburn 100,000 158,558
Marc Holtzman* 23,333 38,484
John Behar* 6,250 10,531
Bruce McNaught 843 1,250
Total Directors’ Remuneration 462,770 725,655
* Resigned during the year.
The Director remuneration consists of monthly/quarterly compensation as per the agreed terms. There 
are no further cash payments or benefits provided to Directors.
DIRECTORS SHARE OPTIONS
The share options in force at 31 March 2015 (subsequently expired in June 2015) and held by current/
past directors are as follows:
No. of Options 
Granted
No. of Options 
Vested
No. of Options 
remaining to be 
Vested
Exercise Price
John Scott 100,000 100,000 0 164p
John Behar 50,000 50,000 0 164p
Total 150,000 150,000 0 ANNUAL REPORT 2014–15
13
FINANCIAL INSTRUMENTS
Details of the use of financial instruments by the Company are contained in note 29 to the attached 
financial statements.
RELATED PARTY TRANSACTIONS
Details of significant related party transactions are contained in note 16 and note 22 to the attached 
financial statements.
INTERNAL CONTROL
The Directors acknowledge their responsibility for the Company’s system of internal control and for 
reviewing its effectiveness. The system of internal control is designed to manage the risk of failure to 
achieve the Company’s strategic objectives. It cannot totally eliminate the risk of failure but will provide 
reasonable, although not absolute, assurance against material misstatement or loss.
GOING CONCERN
After making enquires, the Directors have a reasonable expectation that the Company will have adequate 
resources to continue in operational existence for the foreseeable future. This expectation is based on 
estimates of future potential revenues from the RJ-ON/6 Block that the Company will derive from sale of 
hydrocarbon reserves/resources and availability of adequate debt funding from banks, financial markets 
as well as related parties to support capital investment to enable the Company to undertake appraisal 
and development activities in the Block. For this reason, they continue to adopt the going concern basis 
in preparing the financial statements. Refer Note 27.
DIRECTORS’ RESPONSIBILITIES
The Directors are responsible for preparing the Directors’ reports and consolidated financial statements 
for each financial year which give a true and fair view of the state of affairs of the Group and of the profit 
or loss of the Group for that year. In preparing those financial statements the Directors are required to:
•	
Select suitable accounting policies and apply them consistently;
•	
Make judgements and estimates that are reasonable and prudent;
•	
State whether International Financial Reporting Standards have been followed subject to any 
material departures disclosed and explained in the financial statements; and
•	
Prepare consolidated financial statements on a going concern basis unless it is inappropriate to 
presume that the Group will continue in business.
The Directors confirm that the financial statements comply with the above requirements.
The Directors are responsible for keeping proper accounting records which disclose with reasonable 
accuracy at any time the financial position of the Company and of the Group to enable them to ensure 
that the financial statements comply with the requirements of the Companies (Guernsey) Law, 2008. They 
are also responsible for safeguarding the assets of the Company and hence for taking reasonable steps 
for the provision and detection of fraud and other irregularities.
The Directors are responsible for maintaining the integrity of the corporate financial information included 
on the Group’s website.
Legislation in Guernsey governing the preparation and dissemination of financial information may differ 
from legislation in other jurisdictions. ANNUAL REPORT 2014–15
14
To the best of our knowledge and belief:
•	
The financial statements have been prepared in accordance with International Financial Reporting 
Standards, as adopted by the European Union;
•	
Give a true and fair view of the financial position and results of the Group; and
•	
The financial statements include an analysis of the principal financial instruments specific risks and 
uncertainties faced by the Group. There has not been any material change in business risks and 
uncertainties as described in the Admission Document dated 29 May 2008 save for the continuous 
safe production of gas from the SGL Field on an ongoing basis.
AUDITORS
All of the current Directors have taken all steps that they ought to have taken to make themselves aware 
of any information needed by the Group’s Auditors for the purposes of their audit and to establish that 
the Auditors are aware of that information. The Directors are not aware of any relevant audit information 
of which the Auditors are unaware.
By order of the Board
John Scott
CFO & Director
21 September 2015 ANNUAL REPORT 2014–15
15
r iSkS aNd r iSk maNa GEmENT
In planning our future activities and reacting to changes in our ongoing business environment we seek 
to identify, assess, mitigate and monitor the risks that we face. Considerable effort is made during 
our planning process to reduce and mitigate the various risks to the extent that this is practical and 
commercially sound. Ideally large decisions taken early means that any later adaptation or reaction 
should be small. 
We cannot remove the Company from all risk and the oil and gas industry brings with it many special 
challenges in specific risks. What we can and do strive to achieve is to understand and manage the risk 
environment we work within.
The Company faces the exploration, development and production risks of the oil and gas industry. The 
business relies on extensive engineering, geological and geophysical judgements.
As activities on the Block have grown and generated actual data and experience we have used this 
knowledge to reduce these risks. The Block has over 70 wells drilled to date and over 58 bearing 
hydrocarbons. There has been a decline in the number of wells failing to find hydrocarbons through the 
knowledge gained from almost complete 3D seismic coverage of the SGL and DOC areas built up over 
recent years and the analysis of drilling results from our substantial well inventory. We shall continue to 
de-risk this area of our operations but the risk of a dry hole will never reach zero. The risk of mechanical 
issues or well construction failing remains. However with greater standardization of well design and 
repetition of activities this has reduced.
We currently depend on one customer for the sale of gas and substantially all of our revenues.
The Gas Sales and Purchase Agreement (GSPA) signed with GAIL contains Take or Pay provisions. We 
have actual experience of these provisions working and providing us with certainty of income. GAIL has 
significant financial resources and maintains the strongest credit ratings providing comfort in meeting 
any obligations under our Agreement. Our gas is purchased at our Field and shipped via a GAIL owned 
pipeline to the power plant. The pipeline is purpose built and operating well within its design specification. 
The power plant will have a series of turbines reducing the risk of total shut-down. Already wells and 
infra-structure have been put in place for our subsequent sales expansion giving us idle capacity which 
could be used in the event of production problems.
Our business development may require external financing and our ability to obtain such financing could 
be uncertain.
The Company has obtained 3 bank debt facilities from an expanding group of lenders. These facilities 
were obtained on attractive terms in difficult lending markets. Debt service for these facilities remains 
strong and contributes to our sound borrower track record. In April 2015 further diversification of funding 
was achieved with the issue of medium term notes in Singapore. The Company has benefited from 
consistent support of the majority shareholder particularly reducing the risk of any funding gaps due 
to the delay in closing external finance. The Production Sharing Contract which includes cost recovery 
and the long term sales contract for gas provide and enhanced stream of cash to service debt and give 
protection to lenders.
Our business, revenues and profits may fluctuate with changes in oil and gas prices. Our production is 
mainly gas and has been sold on strong “Take or Pay” contracts which significantly reduces the impact 
of fluctuations in the wider global energy market. However the prevailing prices of oil and gas can have 
a bearing on new contracts and price revisions. 
Natural gas prices in India are generally set by the Government through a variety of mechanisms. Last 
year the Government introduced a new gas pricing mechanism for certain contracts awarded under 
NELP regime which considered a volume weighted average whose calculation included gas prices from 
various consuming countries. Gas produced from the Block owned by the Company is not bound by  ANNUAL REPORT 2014–15
16
this new gas pricing regime as the Block was awarded prior to the implementation of the NELP regime. 
Consequently, we are able to negotiate the price of natural gas with our customers based on market 
conditions. However, the Government’s price regime may affect the overall natural gas market in India, 
sets benchmark for natural gas prices and indirectly may have a material negative impact on our business, 
financial condition and results of operations.
However, the management of the Company is of the view that the contracted gas prices are expected 
to be revised upwards in the upcoming price revision under current contract due to the fact that current 
contracted gas prices is significantly lower than the equivalent energy prices of liquid fuels as well as 
some of the recently reported gas sale contracts under free market pricing regime, which applies to the 
Company. Therefore, Company does not foresee any reason for impairment of its fixed asset in near 
future. 
The oil and gas industry is subject to laws and regulations relating to environmental and safety 
matters in exploration for and the development and production of hydrocarbons. We are bound by 
the environmental laws and regulations applicable to India and satisfy and in some areas exceed these 
requirements by using good industry practice, trained staff and quality equipment.
We are committed to upholding procedures to protect the environment and enforce environmental, 
health, safety and security (“EHSS”) mechanisms through accountability at all levels, suitable policies, 
feedback and full compliance by each employee and contractor to all policies we develop. 
Indus is subject to regulation and supervision by the Government of India covering various aspects of 
our business. The Government has historically played a key role, and is expected to continue to play 
a key role, in regulating, reforming and restructuring the Indian oil and natural gas industry. A major 
platform for shaping the industry has been the award of assets by various rounds under the National 
Exploration Licensing Policy (NELP). Our Block was awarded before the formation of NELP and therefore 
places greater emphasis on our Production Sharing Contract (PSC) in our dealings with Government in 
various forms. To date the Block Management Committee created under our PSC and including multiple 
Government agencies has assisted the development progress we have made so far. We expect our Field 
Development Plan (in preparation) for the area beyond SGL to be fully discussed and reviewed by these 
agencies and once approved give us a plan for the subsequent expansion of activities on the Block. ANNUAL REPORT 2014–15
17
COrpOra TE GOvErNaNCE
The Directors recognise the importance of sound corporate governance and intend for the Company 
to comply with the main provisions of the QCA Guidelines and Guernsey regulations in so far as 
they are appropriate given the Company’s size and stage of development. The Company may take 
additional Corporate Governance measures beyond QCA guidelines and Guernsey regulations as may 
be appropriate considering the Company’s operations from time to time.
The Company has not adopted the UK Corporate Governance Code (“the Code”) and has in line with 
most growing AIM companies adopted practices from both the Code and from the QCA Corporate 
Governance Code for Small and Mid-Size Quoted Companies.
Corporate Governance standards and procedures adopted by the Company are regularly reviewed by 
the Chairman who has maintained dialogue and answered questions of shareholders throughout the 
year. The Chairman has consulted the Nomad on the objectives of Corporate Governance within the 
Company.
BOARD OF DIRECTORS
The Board is responsible for the proper management of the Company. The Board comprises of two 
Executive Directors, Ajay Kalsi (CEO) with John Scott (CFO) and two Non-Executive Directors, Peter 
Cockburn (Chairman) and Bruce McNaught. Marc Holtzman stepped down as a Non-Executive Director in 
October 2014 after the Annual General Meeting. Bruce McNaught joined the Board as a Non-Executive 
Director on 12 January 2015. The resume of the current board members is as outlined in the section 
‘Board and Executive Management’ above.
The Executive Directors bring knowledge of the oil and gas industry and a range of general business 
skills. The Non-Executive Directors form a number of committees to assist in the governance of the 
Company and details are below.
All Directors have access to independent professional advice, at the Company’s expense, if and when 
required.
SUB-COMMITTEES
The Board has appointed the three sub-committees outlined below. The Company has maintained a 
bias to Non-Executive Directors on sub-committees to enhance corporate governance. All of the sub-
committees have met during the year as required.
AUDIT COMMITTEE
The Audit committee comprises of Peter Cockburn as Chairman and Bruce McNaught. The committee 
is responsible for ensuring that the financial performance of the Company is properly monitored and 
reported on and for meeting with the Auditors and reviewing findings of the audit with the external 
auditor. It is authorised to seek any information it properly requires from any employee and may ask 
questions of any employee. It meets the Auditors once per year without any members of management 
being present and is also responsible for considering and making recommendations regarding the 
identity and remuneration of such Auditors.
REMUNERATION COMMITTEE
The Remuneration committee comprises of Peter Cockburn as Chairman and Bruce McNaught. The 
committee considers and recommends to the Board the framework for the remuneration of the executive 
directors of the Company and any other senior management. It further considers and recommends to the 
Board the total individual package of each executive director including bonuses, incentive payments and  ANNUAL REPORT 2014–15
18
share options or other share awards. In addition, subject to existing contractual obligations, it reviews 
the design of all share incentive plans for approval by the Board and the Company’s shareholders and, 
for each such plan, recommends whether awards are made and, if so, the overall amount of such awards, 
the individual awards to executive directors and performance targets to be used. No director is involved 
in decisions concerning his own remuneration.
NOMINATION COMMITTEE
The Nomination committee comprises Peter Cockburn as Chairman, Bruce McNaught and Ajay Kalsi. 
The committee considers the selection and re-appointment of Directors. It identifies and nominates 
candidates to all board vacancies and regularly reviews the structure, size and composition of the board 
(including the skills, knowledge and experience) and makes recommendations to the Board with regard 
to any changes.
SHARE DEALING
The Company has adopted a share dealing code (based on the Model Code) and the Company takes all 
proper and reasonable steps to ensure compliance by Directors and relevant employees.
THE CITY CODE ON TAKEOVERS AND MERGERS
The Code applies to offers for all listed and unlisted public companies considered by the Panel resident 
in the UK, the Channel Islands or the Isle of Man. The Panel normally considers a company to be resident 
only if it is incorporated in the United Kingdom, the Channel Islands or the Isle of Man and has its place 
of central management in one of those jurisdictions. It is emphasised that although the Ordinary Shares 
trades on AIM, the company is not subject to takeover regulations in the UK. However, certain provisions 
analogous to parts of the Code in particular the making of mandatory offers have been incorporated into 
the Articles which are available on the Company website, www.indusgas.com.
DISCLOSURE AND TRANSPARENCY RULES
As a company incorporated in Guernsey, Shareholders are not obliged to disclose their interests in the 
Company in the same way as shareholders of certain companies incorporated in the UK. In particular, the 
relevant provisions of chapter 5 of the DTR do not apply. While the Articles contain provisions requiring 
disclosure of voting rights in Ordinary Shares which are similar to the provisions of the DTR, this may not 
always ensure compliance with the requirements of Rule 17 of the AIM Rules. Furthermore, the Articles 
may be amended in the future by a special resolution of the Shareholders.
CONTROL BY SIGNIFICANT SHAREHOLDER
Gynia Holdings Limited, along with its wholly owned subsidiary Focusoil Inc. owns a significant 
percentage of outstanding shares of the Company. As a significant shareholder, Gynia could exercise 
significant influence over certain corporate governance matters requiring shareholder approval, including 
the election of directors and the approval of significant corporate transactions and other transactions 
requiring a majority vote.
The Company, Arden Partners (Broker & Nomad), Gynia and Mr Ajay Kalsi have entered into a relationship 
agreement to regulate the arrangements between them. The relationship agreement applies for as long 
as Gynia directly or indirectly holds in excess of thirty per cent of the issued share capital of the Company 
and the Company’s shares remain admitted to trading on AIM. The relationship agreement includes 
provisions to ensure that:
 i. The Board and its committees are able to carry on their business independently of the personal 
interests of Gynia;
 ii. The constitutional documents of the Company are not changed in such a way which would be 
inconsistent with the relationship agreement; ANNUAL REPORT 2014–15
19
 iii. All transactions between the Group and Gynia (or its affiliates) are on a normal commercial basis and 
at arm’s length;
 iv. In the event of a conflict of interest between Gynia and the Board, no person who is connected with 
Gynia is appointed as a Non-Executive Director of the Company and no existing Non-Executive 
Director is removed as a director of the Company unless such an appointment or removal has been 
previously approved by the nomination committee of the Board and that to the extent that any 
previously approved by the nomination committees concerns the composition of the Board which 
has been approved by the Board requiring the approval of the shareholders of the Company then 
Gynia will vote its Ordinary Shares in favour; and
 v. Certain restrictions are put in place to prevent interference by the Shareholder with the business of 
the Company. ANNUAL REPORT 2014–15
20
iNduS Ga S l imiTEd aNd iTS SuBSidiariES 
31 mar CH 2015
Independent Auditor’s Report to the Members of Indus Gas Limited
We have audited the consolidated financial statements of Indus Gas Limited (the ‘Company’) for the 
year ended 31 March 2015 which comprise the Consolidated Statement of Financial Position, the 
Consolidated Statement of Comprehensive Income, the Consolidated Statement of Changes in Equity, 
the Consolidated Statement of Cash Flow and the related notes. The financial reporting framework that 
has been applied in their preparation is applicable law and International Financial Reporting Standards 
(IFRSs) as adopted by the European Union (EU).
This report is made solely to the company’s members, as a body, in accordance with Section 262 of 
The Companies (Guernsey) Law, 2008. Our audit work has been undertaken so that we might state to 
the company’s members those matters we are required to state to them in an auditors’ report and for 
no other purpose. To the fullest extent permitted by law, we do not accept or assume responsibility 
to anyone other than the company and the company’s members as a body, for our audit work, for this 
report, or for the opinions we have formed.
Respective responsibilities of directors and auditors
As described in the Statement of Directors’ Responsibilities on page 13 the company’s directors are 
responsible for the preparation of the consolidated financial statements which give a true and fair view.
Our responsibility is to audit and express an opinion on the consolidated financial statements in accordance 
with applicable Law and International Standards on Auditing (UK and Ireland). Those standards require us 
to comply with the Auditing Practices Board’s Ethical Standards for Auditors.
Scope of the audit of the consolidated financial statements
An audit involves obtaining evidence about the amounts and disclosures in the consolidated financial 
statements sufficient to give reasonable assurance that the consolidated financial statements are free 
from material misstatement, whether caused by fraud or error. This includes an assessment of whether 
the accounting policies are appropriate to the Group’s circumstances and have been consistently applied 
and adequately disclosed; the reasonableness of significant accounting estimates made by the directors; 
and the overall presentation of the consolidated financial statements. In addition, we read all the financial 
and non-financial information in the annual report to identify material inconsistencies with the audited 
financial statements and to identify any information that is apparently materially incorrect based on, or 
materially inconsistent with, the knowledge acquired by us in the course of performing the audit. If we 
become aware of any apparent material misstatements or inconsistencies we consider the implications 
for our report.
Opinion on the consolidated financial statements
In our opinion, the consolidated financial statements:
•	
give a true and fair view of the state of the Group’s affairs as at 31 March 2015 and of its profit for 
the year then ended; 
•	
have been properly prepared in accordance with IFRSs as adopted by the EU; and 
•	
comply with the requirements of The Companies (Guernsey) Law, 2008. ANNUAL REPORT 2014–15
21
Matters on which we are required to report by exception
We have nothing to report in respect of the following: 
Under The Companies (Guernsey) Law, 2008 we are required to report to you, if in our opinion:
•	
proper accounting records have not been kept by the Group; or
•	
the consolidated financial statements are not in agreement with the accounting records; or
•	
we have not obtained all the information and explanations, which to the best of our knowledge and 
belief, are necessary for the purposes of our audit. 
Grant Thornton Limited 
Chartered Accountants
St Peter Port, Guernsey, Channel Islands 
21 September 2015 ANNUAL REPORT 2014–15
22
CONSOlida TEd STaTEmENT OF FiNaNCial pOSiTiON
(All amounts in United States Dollars, unless otherwise stated)
Note 31 March 2015
31 March 2014
(Restated)
ASSETS
Non-current assets
Intangible assets: exploration and evaluation assets 6 – –
Property, plant and equipment 7 483,794,473 408,582,251
Tax assets 1,228,787 726,511
Other assets 6,225 885
Total non-current assets 485,029,485 409,309,647
Current assets
Inventories 10 5,231,415 9,326,267
Trade receivables 5,330,484 7,847,404
Other current assets 11 1,317,697 408,645
Cash and cash equivalents 12 12,251,533 977,028
Total current assets 24,131,129 18,559,344
Total assets 509,160,614 427,868,991
LIABILITIES AND EQUITY
Shareholders’ equity
Share capital 13 3,619,443 3,619,443
Additional paid-in capital 13 46,733,689 46,733,689
Currency translation reserve 13 (9,313,781) (9,313,781)
Merger reserve 13 19,570,288 19,570,288
Share option reserve 20 324,865 324,865
Retained earnings 27,225,937 10,981,346
Total shareholders’ equity 88,160,441 71,915,850
LIABILITIES
Non-current liabilities
Long term debt from banks, excluding current portion 14 200,293,945 85,266,117
Provision for decommissioning 15 1,281,862 1,079,946
Deferred tax liabilities (net) 8 26,445,323 12,687,726
Payable to related parties, excluding current portion 16 120,288,834 112,947,262
Deferred revenue 25,563,995 24,618,832
Total non-current liabilities 373,873,959 236,599,883 ANNUAL REPORT 2014–15
23
CONSOlida TEd STaTEmENT OF FiNaNCial pOSiTiON (CONTd.)
(All amounts in United States Dollars, unless otherwise stated)
Note 31 March 2015
31 March 2014
(Restated)
Current liabilities
Current portion of long term debt from banks 14 18,389,976 17,301,889
Current portion payable to related parties 16 23,490,343 96,847,805
Accrued expenses and other liabilities 168,809 126,478
Deferred revenue 5,077,086 5,077,086
Total current liabilities 47,126,214 119,353,258
Total liabilities 421,000,173 355,953,141
Total equity and liabilities 509,160,614 427,868,991
(The accompanying notes are an integral part of these consolidated financial statements)
These consolidated financial statements were approved and authorised for issue by the board on 21 September 
2015 and was signed on its behalf by:
Peter Cockburn
Director ANNUAL REPORT 2014–15
24
CONSOlida TEd STaTEmENT OF COmprEHENSivE iNCOmE
(All amounts in United States Dollars, unless otherwise stated)
Note
Year ended
31 March 2015
Year ended
31 March 2014
Revenues 41,393,184 27,834,635
Cost of sales (8,542,085) (5,454,884)
Gross profit 32,851,099 22,379,751
Cost and expenses
Administrative expenses (2,832,584) (1,453,590)
Operating profit 30,018,515 20,926,161
Foreign currency exchange (loss)/gain 18 (16,469) 78,889
Interest income 141 127
Profit before tax 30,002,187 21,005,177
Income taxes 9
– Deferred tax expense (13,757,596) (9,233,244)
Total comprehensive income for the year (attributable 
to the shareholders of the Group) 16,244,591 11,771,933
Earnings per share 21
Basic 0.09 0.06
Diluted 0.09 0.06
(The accompanying notes are an integral part of these consolidated financial statements) ANNUAL REPORT 2014–15
25
CONSOlida TEd STaTEmENT OF CHaNGES iN EquiT y
(All amounts in United States Dollars, unless otherwise stated)
Common stock
Additional 
paid in 
capital
Currency 
translation 
reserve
Merger 
reserve
Share 
option 
reserve
Retained 
earnings/
(accumulated 
losses)
Total 
shareholders’ 
equity
No. of 
shares
Amount
Balance as at 
1 April 2013
182,973,924 3,619,443 46,733,689 (9,313,781) 19,570,288 324,865 (790,587) 60,143,917
Profit and total 
comprehensive 
income for the 
year
– – – – – – 11,771,933 11,771,933
Balance as at 
31 March 2014
182,973,924 3,619,443 46,733,689 (9,313,781) 19,570,288 324,865 10,981,346 71,915,850
Comprehensive 
income for the 
year
– – – – – – 16,244,591 16,244,591
Balance as at 
31 March 2015
182,973,924 3,619,443 46,733,689 (9,313,781) 19,570,288 324,865 27,225,937 88,160,441
(The accompanying notes are an integral part of these consolidated financial statements) ANNUAL REPORT 2014–15
26
CONSOlida TEd STaTEmENT OF CaSH FlO w
(All amounts in United States Dollars, unless otherwise stated)
Note
Year ended  
31 March 2015
Year ended  
31 March 2014
Cash flow from operating activities
Profit before tax 30,002,187 21,005,177
Adjustments
Loan processing cost (4,100,000) –
Unrealised exchange (gain)/loss 18 16,469 (1,423)
Interest income (141) (127)
Depreciation 7 7,584,042 4,773,127
Changes in operating assets and liabilities
Inventories 4,094,852 (3,351,651)
Trade receivables 2,516,920 2,078,625
Other current and non–current assets 96,938 (365,518)
Deferred revenue 945,163 15,600,222
Payable to related party–operating activities 9,035,452 5,684,190
Accrued expenses and other liabilities 7,454 127,609
Cash generated from operations 50,199,336 45,550,231
Income taxes paid (502,276) (495,655)
Net cash generated from operating activities 49,697,060 45,054,576
Cash flow from investing activities
Purchase of property, plant and equipment
A
(150,716,436) (28,820,986)
Interest received 141 127
Net cash used in investing activities (150,716,295) (28,820,859)
Cash flow from financing activities
Repayment of long term debt from banks (17,320,000) (17,320,000)
Proceeds from long term debt from banks 135,600,000 –
Payment of interest (5,984,930) (5,486,986)
Net cash generated from/(used in) financing activities 112,295,070 (22,806,986)
Net increase/(decrease) in cash and cash equivalents 11,275,835 (6,573,269)
Cash and cash equivalents at the beginning of the year 977,028 7,546,024
Effects of exchange differences on cash and cash equivalents (1,330) 4,273
Cash and cash equivalents at the end of the year 12,251,533 977,028
A
The purchase of property, plant and equipment above, includes additions to exploration and evaluation assets 
amounting to US$ 34,017,324 (previous year: US$ 59,380,804) transferred to development cost, as explained in 
Note 6. 
(The accompanying notes are an integral part of these consolidated financial statements) ANNUAL REPORT 2014–15
27
NOTES TO CONSOlida TEd FiNaNCial STaTEmENTS
(All amounts in United States Dollars, unless otherwise stated)
1. INTRODUCTION
Indus Gas Limited (“Indus Gas” or “the Company”) was incorporated in the Island of Guernsey on 4 March 
2008 pursuant to an Act of the Royal Court of the Island of Guernsey. The Company was set up to act as the 
holding company of iServices Investments Limited. (“iServices”) and Newbury Oil Co. Limited (“Newbury”). 
iServices and Newbury are companies incorporated in Mauritius and Cyprus, respectively. iServices was 
incorporated on 18 June 2003 and Newbury was incorporated on 17 February 2005. The Company was 
listed on the Alternative Investment Market (AIM) of the London Stock Exchange on 6 June 2008. Indus Gas 
through its wholly owned subsidiaries iServices and Newbury (hereinafter collectively referred to as “the 
Group”) is engaged in the business of oil and gas exploration, development and production.
Focus Energy Limited (“Focus”), an entity incorporated in India, entered into a Production Sharing Contract 
(“PSC”) with the Government of India (“GOI”) and Oil and Natural Gas Corporation Limited (“ONGC”) on 
30 June 1998 for petroleum exploration and development concession in India known as RJ-ON/06 (“the 
Block”). Focus is the Operator of the Block. On 13 January 2006, iServices and Newbury entered into 
an interest sharing agreement with Focus and obtained a 65 per cent and 25 per cent share respectively 
in the Block. Consequent to this, the Group acquired an aggregate of 90 per cent participating interest 
in the Block and the balance 10 per cent of participating interest is owned by Focus. The participating 
interest explained above is subject to any option exercised by ONGC in respect of individual wells (already 
exercised for SGL field as further explained in Note 3).
2. GENERAL INFORMATION
The consolidated financial statements of the Group have been prepared in accordance with International 
Financial Reporting Standards (‘IFRS’) as adopted by the European Union (‘EU’). The consolidated 
financial statements have been prepared on a going concern basis (refer to note 27), and are presented in 
United States Dollar (US$). The functional currency of the Company as well as its subsidiaries is US$.
3. JOINTLY CONTROLLED ASSETS
The Group participates in an unincorporated joint arrangement with Focus wherein the Group’s interest 
in this arrangement was classified as jointly controlled assets. Following implementation of IFRS 11: Joint 
Arrangements, the Group’s interest in this arrangement is now classified as Joint operation. All rights and 
obligations in respect of exploration, development and production of oil and gas resources under the 
‘Interest sharing agreement’ are shared between Focus, iServices and Newbury in the ratio of 10 per cent, 
65 per cent and 25 per cent respectively. 
Under the PSC, the GOI, through ONGC has an option to acquire a 30 per cent participating interest in 
any discovered field, upon such successful discovery of oil or gas reserves, which has been declared as 
commercially feasible to develop. 
Subsequent to the declaration of commercial discovery in SGL field on 21 January 2008, ONGC had 
exercised the option to acquire a 30 per cent participating interest in the discovered fields on 6 June 2008. 
The exercise of this option would reduce the interest of the existing partners proportionately.
On exercise of this option, ONGC is liable to pay its share of 30 per cent of the SGL field development 
costs and production costs incurred after 21 January 2008 and are entitled to a 30 per cent share in the 
production of gas subject to recovery of Contract costs as explained below. 
The allocation of the production from the field to each participant in any year is determined on the basis 
of the respective proportion of each participant’s cumulative unrecovered contract costs as at the end 
of the previous year or where there are no unrecovered contract cost at the end of previous year on the 
basis of participating interest of each such participant in the field. For recovery of past contract cost,  ANNUAL REPORT 2014–15
28
production from the field is first allocated towards exploration and evaluation cost and thereafter towards 
development cost.
On the basis of the above, gas production for the years ended 31 March 2015 and 2014 is shared between 
Focus, iServices and Newbury in the ratio of 10 per cent, 65 per cent and 25 per cent, respectively. 
The aggregate amounts relating to jointly controlled assets, liabilities, expenses and commitments related 
thereto that have been included in the consolidated financial statements are as follows:
31 March 2015 31 March 2014
Non-current assets 483,794,473 408,582,251
Current assets 5,231,415 9,326,267
Non-current liabilities 1,281,862 1,079,946
Current liabilities 23,490,343 96,847,805
Expenses (net of finance income) 9,035,452 5,684,190
Commitments NIL NIL
The GOI, through ONGC, has option to acquire similar participating interest in any future successful 
discovery of oil or gas reserves in the Block.
4. STANDARDS AND INTERPRETATIONS ISSUED BUT NOT EFFECTIVE AND YET TO BE 
APPLIED BY THE GROUP
Summarised in the paragraphs below are standards, interpretations or amendments that have been issued 
prior to the date of approval of these consolidated financial statements and endorsed by EU and will be 
applicable for transactions in the Group but are not yet effective. These have not been adopted early by 
the Group and accordingly, have not been considered in the preparation of the consolidated financial 
statements of the Group.
Management anticipates that all of these pronouncements will be adopted by the Group in the first 
accounting period beginning after the effective date of each of the pronouncements. Information on 
the new standards, interpretations and amendments that are expected to be relevant to the Group’s 
consolidated financial statements is provided below.
•	 IFRS 9	Financial	Instruments	Classification	and	Measurement
In July 2014, the International Accounting Standards Board issued the ﬁnal version of IFRS 9, Financial 
Instruments. The standard reduces the complexity of the current rules on ﬁnancial instruments as mandated 
in IAS 39. IFRS 9 has fewer classiﬁcation and measurement categories as compared to IAS 39 and has 
eliminated the categories of held to maturity, available for sale and loans and receivables. Further it 
eliminates the rule-based requirement of segregating embedded derivatives and tainting rules pertaining 
to held to maturity investments. For an investment in an equity instrument which is not held for trading, 
IFRS 9 permits an irrevocable election, on initial recognition, on an individual share-by-share basis, to 
present all fair value changes from the investment in other comprehensive income. No amount recognized 
in other comprehensive income would ever be reclassiﬁed to proﬁt or loss. It requires the entity, which 
chooses to measure a liability at fair value, to present the portion of the fair value change attributable to 
the entity’s own credit risk in other comprehensive income.
IFRS 9 replaces the ‘incurred loss model’ in IAS 39 with an ‘expected credit loss’ model. The measurement 
uses a dual measurement approach, under which the loss allowance is measured as either 12 month 
expected credit losses or lifetime expected credit losses. The standard also introduces new presentation 
and disclosure requirements. ANNUAL REPORT 2014–15
29
This standard is effective for reporting periods beginning on or after 1 January 2018 with early adoption 
permitted. The management is currently evaluating the impact that this new standard will have on its 
consolidated financial statements.
•	 IFRS	15	Revenue	from	Contracts	with	Customers
The International Accounting Standards Board (IASB) has published a new standard, IFRS 15 Revenue from 
Contracts with customers. This standard replaces IAS 11 Construction Contracts, IAS 18 Revenue, IFRIC 13 
Customer Loyalty Programmes, IFRIC 15 Agreements for the Construction of Real Estate, IFRIC 18 Transfers 
of Assets from Customers, and SIC-31 Revenue- Barter Transactions involving advertising services. It sets 
out the requirements for recognising revenue that apply to contracts with customers, except for those 
covered by standards on leases, insurance contracts and financial instruments.
The new standard establishes a control-based revenue recognition model and provides additional guidance 
in many areas not covered in detail under existing IFRSs, including how to account for arrangements with 
multiple performance obligations, variable pricing, customer refund rights, supplier repurchase options, 
and other common complexities.
This standard is effective for reporting periods beginning on or after 1 January 2017 with early adoption 
permitted. It applies to new contracts created on or after the effective date and to the existing contracts 
that are not yet complete as of the effective date.
The management is currently evaluating the impact that this new standard will have on its consolidated 
financial statements.
5. SUMMARY OF ACCOUNTING POLICIES
The consolidated financial statements have been prepared on a historical basis, except where specified 
below. A summary of the significant accounting policies applied in the preparation of the accompanying 
consolidated financial statements are detailed below:
5.1. BASIS OF CONSOLIDATION
The consolidated financial statements include the financial statements of the parent company and all of 
its subsidiary undertakings drawn up to 31 March 2015. The Group consolidates entities which it controls. 
Control exists when the parent has power over the entity, is exposed, or has rights, to variable returns from 
its involvement with the entity and has the ability to affect those returns by using its power over the entity. 
Power is demonstrated through existing rights that give the ability to direct relevant activities, those which 
significantly affect the entity’s returns.
The Group recognises in relation to its interest in a joint operation: 
a. its assets, including its share of any assets held jointly; 
b. its liabilities, including its share of any liabilities incurred jointly; 
c. its revenue from the sale of its share of the output arising from the joint operation;
d. its share of the revenue from the sale of the output by the joint operation; and
e. its expenses, including its share of any expenses incurred jointly.
Intra-Group balances and transactions, and any unrealised gains and losses arising from intra-Group 
transactions are eliminated in preparing the consolidated financial statements. Amounts reported in the 
financial statements of subsidiaries have been adjusted where necessary to ensure consistency with the 
accounting policies adopted by the Group. 
Profit or losses of subsidiaries acquired or disposed of during the year are recognised from the date of 
control of acquisition, or up to the effective date of disposal, as applicable.  ANNUAL REPORT 2014–15
30
5.2. SIGNIFICANT ACCOUNTING JUDGEMENTS AND ESTIMATES
In preparing consolidated financial statements, the Group’s management is required to make judgements, 
estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of 
contingent assets and liabilities at the date of the financial statement and the reported amounts of revenues 
and expenses during the reporting period.  Although these estimates are based on management’s best 
knowledge of current events and actions, actual results may ultimately differ from those estimates. The 
management’s estimates for the useful life and residual value of tangible assets, impairment of tangible and 
intangible assets and recognition of provision for decommissioning represent certain particularly sensitive 
estimates. The estimates and underlying assumptions are reviewed on an on-going basis. Revisions to 
accounting estimates are recognised in the period in which the estimate is revised if the revision affects 
only that period or in the period of the revision and future periods if the revision affects both current and 
future periods. Information about significant judgements, estimates and assumptions that have the most 
significant effect on recognition and measurement of assets, liabilities, income and expenses is provided 
in note 26.
5.3. FOREIGN CURRENCIES
The consolidated financial statements have been presented in US$.
Foreign currency transactions are translated into the functional currency of the respective Group entities, 
using the exchange rates prevailing at the dates of the transactions (spot exchange rate). Functional 
currency is the currency of the primary economic environment in which the entity operates. 
Foreign exchange gains and losses resulting from the settlement of such transactions and from the re-
measurement of monetary items at year-end exchange rates are recognised in the profit or loss for the year.
Non-monetary items measured at historical cost are recorded in the functional currency of the entity using 
the exchange rates at the date of the transaction.
5.4. REVENUE RECOGNITION
Revenue from the sale of natural gas and condensate production (a by-product) is recognised when the 
significant risks and rewards of ownership have been transferred, which is when title passes to the customer. 
This occurs when product is physically transferred into a vessel, pipe or other delivery mechanism. 
Revenue is stated after deducting sales taxes, excise duties and similar levies.
Per the ‘Take-or-Pay’ agreement, GAIL (India) Limited (‘GAIL’ or the ‘customer’) is committed towards 
taking a certain minimum quantity of gas and paying for any related shortfall. The Group’s entitlement to 
receive revenue for any shortfall is recorded as trade receivables with a corresponding credit to deferred 
revenue. Until the expiry of the contracted period, the Group continues to have an obligation to deliver the 
deficit to GAIL. Revenue for the deficit quantity would be recognised at the earlier of delivery of physical 
quantity towards the deficit to GAIL or at the expiry of the contract period. Deferred revenue represents 
amounts received/due from GAIL for which gas is yet to be delivered. 
5.5. PROPERTY, PLANT AND EQUIPMENT 
Property, plant and equipment comprises of Development assets and other properties, plant and equipment 
used in the gas fields and for administrative purposes. These assets are stated at cost plus decommissioning 
cost less accumulated depreciation and any accumulated impairment losses. 
Development assets are accumulated on a field by field basis and comprise of costs of developing the 
commercially feasible reserve, expenditure on the construction, installation or completion of infrastructure 
facilities such as platforms, pipelines and other costs of bringing such reserves into production. It also 
includes the exploration and evaluation costs incurred in discovering the commercially feasible reserve, 
which have been transferred from the exploration and evaluation assets as per the policy mentioned in note 
5.6. As consistent with the full cost method, all exploration and evaluation expenditure incurred up to the 
date of the commercial discovery have been classified under development assets of that field.  ANNUAL REPORT 2014–15
31
The carrying values of property, plant and equipment are reviewed for impairment when events or changes 
in circumstances indicate that the carrying values may not be recoverable.
An item of property, plant and equipment is derecognised upon disposal or when no future economic 
benefits are expected from its use or disposal. Any gain or loss arising on de-recognition of the asset 
(calculated as the difference between the net disposal proceeds and the carrying amount of the asset) is 
included in the profit or loss of the year in which the asset is derecognised. However, where the asset is 
being consumed in developing exploration and evaluation intangible assets, such gain or loss is recognised 
as part of the cost of the intangible asset.
The asset’s residual values, useful lives and depreciation methods are reviewed, and adjusted if appropriate, 
at each period end. No depreciation is charged on development assets until production commences. 
Depreciation on property, plant and equipment is provided at rates estimated by the management. 
Depreciation is computed using the straight line method of depreciation, whereby each asset is written 
down to its estimated residual value evenly over its expected useful life. The useful lives estimated by the 
management are as follows:
Extended well test equipment 20 years
Bunk houses 5 years
Vehicles 5 years
Other assets
Furniture and fixture 5 years
Buildings 10 years
Computer equipment 3 years
Other equipment 5 years
Land acquired is recognised at cost and no depreciation is charged as it has an unlimited useful life.
Production assets are depreciated from the date of commencement of production, on a field by field basis 
with reference to the unit of production method for the commercially probable and proven reserves in the 
particular field.
Advances paid for the acquisition/construction of property, plant and equipment which are outstanding as 
at the end of the reporting period and the cost of property, plant and equipment under construction before 
such date are disclosed as ‘Capital work-in-progress’.
5.6. EXPLORATION AND EVALUATION ASSETS
The Group adopts the full cost method of accounting for its oil and gas interests, having regard to the 
requirements of IFRS 6: Exploration for and Evaluation of Mineral Resources. Under the full cost method 
of accounting, all costs of exploring for and evaluating oil and gas properties, whether productive or not 
are accumulated and capitalised by reference to appropriate cost pools. Such cost pools are based on 
geographic areas and are not larger than a segment. The Group currently has one cost pool being an area 
of land located in Rajasthan, India.
Exploration and evaluation costs may include costs of licence acquisition, directly attributable exploration 
costs such as technical services and studies, seismic data acquisition and processing, exploration drilling 
and testing, technical feasibility, commercial viability costs, finance costs to the extent they are directly 
attributable to financing these activities and an allocation of administrative and salary costs as determined 
by management. All costs incurred prior to the award of an exploration licence are written off as a loss in 
the year incurred.
Exploration and evaluation costs are classified as tangible or intangible according to the nature of the 
assets acquired and the classification is applied consistently. Tangible exploration and evaluation assets are 
recognised and measured in accordance with the accounting policy on property, plant and equipment. To 
the extent that such a tangible asset is consumed in developing an intangible exploration and evaluation 
asset, the amount reflecting that consumption is recorded as part of the cost of the intangible asset. ANNUAL REPORT 2014–15
32
Exploration and evaluation assets are not amortised prior to the conclusion of appraisal activities. Where 
technical feasibility and commercial viability is demonstrated, the carrying value of the relevant exploration 
and evaluation asset is reclassified as a development and production asset and tested for impairment on 
the date of reclassification. Impairment loss, if any, is recognised.
5.7. IMPAIRMENT TESTING FOR EXPLORATION AND EVALUATION ASSETS AND PROPERTY, 
PLANT AND EQUIPMENT
An impairment loss is recognised for the amount by which an asset’s or cash-generating unit’s carrying 
amount exceeds its recoverable amount. The recoverable amount is the higher of fair value, reflecting 
market conditions less costs to sell, and value in use based on an internal discounted cash flow evaluation.
Where there are indicators that an exploration asset may be impaired, the exploration and evaluation 
assets are grouped with all development/producing assets belonging to the same geographic segment to 
form the Cash Generating Unit (CGU) for impairment testing. Where there are indicators that an item of 
property, plant and equipment asset is impaired, assets are grouped at the lowest levels for which there are 
separately identifiable cash flows to form the CGU. The combined cost of the CGU is compared against the 
CGU’s recoverable amount and any resulting impairment loss is written off in the profit or loss of the year. 
No impairment has been recognised during the year.
An assessment is made at each reporting date as to whether there is any indication that previously 
recognised impairment losses may no longer exist or may have decreased. If such indication exists, the 
Group estimates the asset’s or CGU’s recoverable amount. A previously recognised impairment loss is 
reversed only if there has been a change in the assumptions used to determine the asset’s recoverable 
amount since the last impairment loss was recognised. The reversal is limited so that the carrying amount of 
the asset does not exceed its recoverable amount, nor exceed the carrying amount that would have been 
determined, net of depreciation, had no impairment loss been recognised for the asset in prior years. Such 
reversal is recognised in profit or loss unless the asset is carried at a re-valued amount, in which case the 
reversal is treated as a revaluation increase.
5.8. FINANCIAL ASSETS
Financial assets and financial liabilities are recognised on the Group’s Statement of Financial Position when 
the Group has become a party to the contractual provisions of the related instruments.
Financial assets of the Group, under the scope of IAS 39 ‘Financial Instruments: Recognition and 
Measurement’ fall into the category of loans and receivables. When financial assets are recognised initially, 
they are measured at fair value plus transaction costs. The Group determines the classification of its financial 
assets at initial recognition. 
Loans and receivables are non-derivative financial assets with fixed or determinable payments that are 
not quoted in an active market. Such assets are subsequently carried at amortised cost using the effective 
interest method, less provision for impairment. Gains and losses are recognised in profit or loss when the 
loans and receivables are derecognised or impaired, as well as through the amortisation process.
Loans and receivables are assessed for indicators of impairment at the end of each reporting period. Loans 
and receivables are considered to be impaired when there is objective evidence that, as a result of one or 
more events that occurred after the initial recognition, the estimated future cash flows have been affected. 
De-recognition of loans and receivables occur when the rights to receive cash flows from the instrument 
expire or are transferred and substantially all of the risks and rewards of ownership have been transferred. 
5.9. FINANCIAL LIABILITIES 
The Group’s financial liabilities include debts, trade and other payables and loans from related parties. 
Financial liabilities are recognised when the Group becomes a party to the contractual agreements of the 
related instrument.  ANNUAL REPORT 2014–15
33
Financial liabilities are recognised at their fair value less transaction costs and subsequently measured at 
amortised cost less settlement payments. Amortised cost is computed using the effective interest method.
Trade and other payables and loans from related parties are interest free financial liabilities with maturity 
period of less than twelve months and are carried at a transaction value that is not materially different from 
their fair value.
A financial liability is 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
Income tax assets and/or liabilities comprise those obligations to, or claims from, fiscal authorities relating 
to the current or prior reporting period that are unpaid/un-recovered at the date of the Statement of 
Financial Position. They are calculated according to the tax rates and tax laws applicable to the fiscal 
periods to which they relate, based on the taxable profit for the year. All changes to current tax assets or 
liabilities are recognised as a component of tax expense in profit or loss. 
Deferred income taxes are calculated using the balance sheet method on temporary differences. This 
involves the comparison of the carrying amounts of assets and liabilities in the financial statement with their 
tax base. Deferred tax is, however, neither provided on the initial recognition of goodwill, nor on the initial 
recognition of an asset or liability unless the related transaction is a business combination or affects tax or 
accounting profit. Tax losses available to be carried forward as well as other income tax credits to the Group 
are assessed for recognition as deferred tax assets.
Deferred tax liabilities are always provided for in full. Deferred tax assets are recognised to the extent that 
it is probable that they will be offset against future taxable income. Deferred tax assets and liabilities are 
calculated, without discounting, at tax rates and laws that are expected to apply to their respective period 
of realization, provided they are enacted or substantively enacted at the date of the statement of financial 
position. ANNUAL REPORT 2014–15
34
Changes in deferred tax assets or liabilities are recognised as a component of tax expense in profit or loss 
of the year, except where they relate to items that are charged or credited directly to other comprehensive 
income or equity in which case the related deferred tax is also charged or credited directly to other 
comprehensive income or equity.
5.13. BORROWING COSTS
Any interest payable on funds borrowed for the purpose of obtaining qualifying assets, which are assets 
that necessarily take a substantial period of time to get ready for their intended use or sale, is capitalised 
as a cost of that asset until such time as the assets are substantially ready for their intended use or sale. 
Investment income earned on the temporary investment of specific borrowings pending their expenditure 
on qualifying assets is deducted from the borrowing costs eligible for capitalisation.
Any associated interest charge from funds borrowed principally to address a short-term cash flow shortfall 
during the suspension of development activities is expensed in the period.
Transaction costs incurred towards an un-utilised debt facility are treated as prepayments to be adjusted 
against the carrying value of debt as and when drawn.
5.14. CASH AND CASH EQUIVALENTS
Cash and cash equivalents include cash in hand, at bank in demand deposits and deposit with maturities 
of 3 months or less from inception, which are readily convertible to known amounts of cash. These assets 
are subject to an insignificant risk of change in value. Cash and cash equivalents are classified as loans and 
receivables under the financial instruments category.
5.15. LEASING ACTIVITIES
Finance leases which transfer substantially all the risks and benefits incidental to ownership of the leased 
item, are capitalised at the inception of the lease, at the fair value of the leased property or the present 
value of the minimum lease payments, whichever is lower.
Lease payments are apportioned between the finance charges and reduction of the lease liability so as to 
achieve a constant rate of interest on the remaining balance of the liability. Finance charges are charged 
directly in profit or loss of the year.
All leases other than finance leases are treated as operating leases. Operating lease payments are 
recognised as an expense in profit or loss on the straight line basis over the lease term.
Where the lease payments in respect of operating leases are made for exploration and evaluation activities 
or development and production activities, these are capitalized as part of the cost of these assets.
5.16. OTHER PROVISIONS AND CONTINGENT LIABILITIES
Provisions are recognised when the Group has a present obligation (legal or constructive) as a result of 
a past event, it is probable that an outflow of resources embodying economic benefits will be required 
to settle the obligation and a reliable estimate can be made of the amount of the obligation. Where the 
Group expects some or all of a provision to be reimbursed, for example under an insurance contract, the 
reimbursement is recognised as a separate asset but only when the reimbursement is virtually certain. The 
expense relating to any provision net of any reimbursement is recognized in profit or loss of the year. To 
the extent such expense is incurred for construction or development of any asset, it is included in the cost 
of that asset. If the effect of the time value of money is material, provisions are determined by discounting 
the expected future cash flows at a pre-tax rate that reflects current market assessments of the time value 
of money and, where appropriate, the risks specific to the liability. Where discounting is used, the increase 
in the provision due to the passage of time is recognised as other finance expenses. 
Provisions include decommissioning provisions representing management’s best estimate of the Group’s 
liability for restoring the sites of drilled wells to their original status. Provision for decommissioning is 
recognised when the Group has an obligation and a reliable estimate can be made. The amount recognised  ANNUAL REPORT 2014–15
35
is the present value of the estimated future expenditure. A corresponding item of property, plant and 
equipment of an amount equivalent to the provision is also recognised and is subsequently depreciated as 
part of the asset. The unwinding discount is recognised as a finance cost.
Commitments and contingent liabilities are not recognised in the financial statements. They are disclosed 
unless the possibility of an outflow of resources embodying economic benefits is remote. 
A contingent asset is not recognised but disclosed in the financial statements when an inflow of economic 
benefits is probable but when it is virtually certain than the asset is recognised in the financial statements.
In those cases where the possible outflow of economic resource as a result of present obligations is 
considered improbable or remote, or the amount to be provided for cannot be measured reliably, no 
liability is recognised in the statement of financial position and no disclosure is made.
5.17. SEGMENT REPORTING
Operating segments are identified on the basis of internal reports about components of the Group that are 
regularly reviewed by the chief operating decision maker in order to allocate resources to the segments 
and to assess their performance. The Company considers that it operates in a single operating segment 
being the production and sale of gas.
5.18. ADOPTION OF NEW STANDARDS BECOMING APPLICABLE DURING THE YEAR
The Group has adopted the following new standards and amendment to standards, including any 
consequential amendment to other standards, with a date of initial application from 1 April 2014.
•	 IFRS	10	Consolidated	Financial	Statements
IFRS 10 supersedes IAS 27 ‘Consolidated and Separate Financial Statements’ (IAS 27) and SIC12 
‘Consolidation-Special Purpose Entities’. IFRS 10 revises the definition of control and provides extensive 
new guidance on its application. These new requirements have the potential to affect which of the 
Group’s investees are considered to be subsidiaries and therefore to change the scope of consolidation. 
The requirements on consolidation procedures, accounting for changes in non-controlling interests and 
accounting for loss of control of a subsidiary are unchanged.
Management has reviewed its control assessments in accordance with IFRS 10 and has concluded that 
there is no effect on the classification (as subsidiaries or otherwise) of any of the Group’s investees held 
during the period or comparative periods covered by these consolidated financial statements.
•	 IFRS	11	Joint	Arrangements
“Joint Arrangements” (“IFRS 11”), which replaces IAS 31, “Interests in Joint Ventures” and SIC-13, “Jointly 
Controlled Entities - Non-monetary Contributions by Ventures”, requires a single method, known as the 
equity method, to account for interests in joint ventures. The proportionate consolidation method to 
account for joint ventures is no longer permitted to be used. IAS 28, “Investments in Associates and 
Joint Ventures”, was amended as a consequence of the issuance of IFRS 11. In addition to prescribing the 
accounting for investments in associates, it now sets out the requirements for the application of the equity 
method when accounting for joint ventures. The application of the equity method has not changed as a 
result of this amendment.
The management has made the disclosures as required by IFRS 11 in these consolidated financial statements. 
There was no impact on the results for the year as a result of the adoption.
•	 IFRS	12	Disclosure	of	interests	in	other	entities
IFRS 12 combines the disclosure requirements for subsidiaries, joint arrangements, associates and 
unconsolidated structured entities within a comprehensive disclosure standard.
It aims to provide more transparency on ‘borderline’ consolidation decisions and enhance disclosures about 
unconsolidated structured entities in which an investor or sponsor has involvement. ANNUAL REPORT 2014–15
36
Subsequent to issuing the new standards the IASB made some changes to the transitional provisions in 
IFRS 10, IFRS 11, and IFRS 12. The guidance confirms that the entity is not required to apply IFRS 10 
retrospectively in certain circumstances and clarifies the requirements to present adjusted comparatives. 
The guidance also makes changes to IFRS 11 and IFRS 12 which provide similar relief from the presentation 
or adjustment of comparative information for periods prior to the immediately preceding period. Further, it 
provides additional relief by removing the requirement to present comparatives for the disclosures relating 
to unconsolidated structured entities for any periods before the first annual period for which IFRS 12 is 
applied.
Consequent to adoption of IFRS 12, the management has made these necessary disclosures in the 
consolidated financial statements.
6. INTANGIBLE ASSETS: EXPLORATION AND EVALUATION ASSETS
Intangible assets comprise of exploration and evaluation assets. Movement in intangible assets is as below: 
Intangible assets: 
exploration and 
evaluation assets
Balance as at 1 April 2013 18,427,390
Additions
A
59,380,804
Transfer to development assets
B
(77,808,194)
Balance as at 31 March 2014 –
Additions
A
34,017,324
Transfer to development assets
B
(34,017,324)
Balance as at 31 March 2015 –
A
The above includes borrowing costs of US$ 930,056 (previous year: US$ 2,810,610). The weighted average capitalisation 
rate on funds borrowed generally is 5.62 per cent per annum (previous year: 6.02 per cent per annum).
B
On 19 November 2013, Focus Energy Limited submitted an integrated declaration of commerciality (DOC) to the 
Directorate General of Hydrocarbons, ONGC, the Government of India and the Ministry of Petroleum and Natural Gas. 
Upon submission of DOC, exploration and evaluation cost incurred on SSF and SSG field was transferred to development 
cost. Focus continues to carry out further appraisal activities in the Block, and exploration and evaluation cost incurred 
subsequent to 19 November 2013, to the extent considered recoverable as per DOC submitted by Focus, is immediately 
transferred on incurrence to development assets. ANNUAL REPORT 2014–15
37
7. PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment comprise of the following:
Cost Land
Extended 
well test 
equipment
Development/ 
Production 
assets
Bunk 
Houses
Vehicles
B
Other 
assets
Capital 
work-in-
progress
Total
Balance as at  
1 April 2013
36,437 3,577,517 309,075,831 5,233,802 4,780,493 1,423,900 2,004,272 326,132,252
Additions/transfers 130,811 153,920 98,306,895 150,729 24,009 54,668 426,576 99,247,608
Disposals/transfers – – (317,476) – – – (1,024,519) (1,341,995)
Balance as at  
31 March 2014
167,248 3,731,437 407,065,250 5,384,531 4,804,502 1,478,568 1,406,329 424,037,865
Additions/transfers  – 6,217 84,319,739 532,992 – 14,180 353,232 85,226,360
Disposals/transfers   – – (40,547) – (227,699) – (569,708) (837,954)
Balance as at 
March 2015
167,248 3,737,654 491,344,442 5,917,523 4,576,803 1,492,748 1,189,853 508,426,271
Accumulated 
Depreciation
Balance as at  
1 April 2013
 – 709,656 2,149,500 2,943,680 1,778,168 958,165 – 8,539,169
Depreciation for  
the year
 – 334,288 4,773,127 831,921 741,570 235,539 – 6,916,445
Balance as at  
31 March 2014
 – 1,043,944 6,922,627 3,775,601 2,519,738 1,193,704 – 15,455,614
Depreciation for  
the year 
 – 325,707 7,584,042 741,184 358,992 166,259 – 9,176,184
Balance as at  
31 March 2015 
 – 1,369,651 14,506,669 4,516,785 2,878,730 1,359,963 – 24,631,798
Carrying values
At 31 March 2014 167,248 2,687,493 400,142,623 1,608,930 2,284,764 284,864 1,406,329 408,582,251
At 31 March 2015 167,248 2,368,003 476,837,773 1,400,738 1,698,073 132,785 1,189,853 483,794,473
The balances above represent the Group’s share in property, plant and equipment as per Note 3. 
Tangible assets comprise of development /production assets in respect of SGL field and development 
assets in respect of SSF and SSG field.
Development assets of SGL field includes the amount of exploration and evaluation expenditure transferred 
to development cost on the date of the first commercial discovery declared by the Group in 2012 and also 
includes expenditure incurred for the drilling of further wells in the SGL field to enhance the production 
activity. Production assets in respect of SGL field includes completed production facilities and under 
construction Gas gathering station - 2. The Group commenced the production facility in October 2012, 
and accordingly such production assets have been depreciated since this date. ANNUAL REPORT 2014–15
38
Development assets of SSF and SSG are explained in note 6. Pending the assessment of these reserves by 
the Directorate General of Hydrocarbons, ONGC, the Government of India and the Ministry of Petroleum 
and Natural Gas and completion of development for production activities, no depreciation has been 
charged on the same.
The additions in Development/Production assets also include borrowing costs US$14,268,842 (previous 
year: US$ 10,281,753). The weighted average capitalisation rate on funds borrowed generally is 5.62 per 
cent per annum (previous year 6.02 per cent).
The depreciation has been included in the following headings:
  31 March 2015 31 March 2014
Depreciation included in exploration and evaluation assets – 1,602,375
Depreciation included in development assets 1,592,142 540,943
Depreciation included in statement of comprehensive 
income under the head cost of sales
7,584,042 4,773,127
Total 9,176,184 6,916,445
8. DEFERRED TAX ASSETS/LIABILITIES (NET)
Deferred taxes arising from temporary differences are summarized as follows: 
31 March 2015 31 March 2014
Deferred tax assets
Unabsorbed losses/credits 177,861,949 142,330,042
Total 177,861,949 142,330,042
Deferred tax liability
Development assets/property, plant and equipment 204,307,272 155,017,768
Total 204,307,272 155,017,768
Net deferred tax liabilities 26,445,323 12,687,726
a) The Group has recognised deferred tax assets on all of its unused tax losses/unabsorbed depreciation 
considering there is convincing evidence of availability of sufficient taxable profit in the Group in the 
future as summarized in note 9. 
b) The deferred tax movements during the current year have been recognised in the Consolidated 
Statement of Comprehensive income.
9. INCOME TAXES 
Income tax is based on the tax rates applicable on profit or loss in various jurisdictions in which the Group 
operates. The effective tax at the domestic rates applicable to profits in the country concerned as shown in 
the reconciliation below have been computed by multiplying the accounting profit by the effective tax rate 
in each jurisdiction in which the Group operates. The individual entity amounts have then been aggregated 
for the consolidated financial statements. The effective tax rate applied in each individual entity has not 
been disclosed in the tax reconciliation below as the amounts aggregated for individual Group entities 
would not be a meaningful number.
Income tax credit is arising on account of the following:
  31 March 2015 31 March 2014
Current tax – –
Deferred tax charge (13,757,596) (9,233,244)
Total (13,757,596) (9,233,244) ANNUAL REPORT 2014–15
39
The relationship between the expected tax expense based on the domestic tax rates for each of the legal 
entities within the Group and the reported tax expense in profit or loss is reconciled as follows: 
  31 March 2015 31 March 2014
Accounting profit for the year before tax 30,002,187 21,005,177
Effective tax at the domestic rates applicable to profits 
in the country concerned
12,852,937 8,870,486
Impact of change in tax rate on deferred tax 147,873 –
Non allowable expenses 756,786 362,758
Tax expense 13,757,596 9,233,244
The reconciliation shown above has been based on the rate 42.84 per cent (previous year: 42.23 per cent) 
as applicable under Indian tax laws.
Indus Gas profits are taxable as per the tax laws applicable in Guernsey where zero per cent tax rate has 
been prescribed for corporates. Accordingly, there is no tax liability for the Group in Guernsey. iServices 
and Newbury being participants in the PSC are covered under the Indian Income tax laws as well as tax laws 
for their respective countries. However, considering the existence of double tax avoidance arrangement 
between Cyprus and India, and Mauritius and India, profits in Newbury and iServices are not likely to attract 
any additional tax in their local jurisdiction. Under Indian tax laws, Newbury and iServices are allowed to 
claim the entire expenditure in respect of the Oil Block incurred until the start of commercial production 
(whether included in the exploration and evaluation assets or development assets) as deductible expense 
in the first year of commercial production or over a period of 10 years. The Company has opted to claim 
the expenditure in the first year of commercial production. As the Group has commenced commercial 
production in 2011 and has generated profits in Newbury and iServices, the management believes there is 
reasonable certainty of utilisation of such losses in the future years and thus a deferred tax asset has been 
created in respect of these.
10. INVENTORIES
Inventories comprise of the following:
31 March 2015 31 March 2014
Drilling and production stores and spares 5,045,918 8,455,623
Fuel 46,703 49,294
Goods in transit 138,794 821,350
Total 5,231,415 9,326,267
The above inventories are held for use in the exploration, development and production activities. These are 
valued at cost determined based on policy explained in paragraph 5.10.
Inventories of US$ 395,942 (previous year: US$ 224,491) were recorded as an expense under the heading 
‘cost of sales’ in the consolidated statement of comprehensive income during the year ended 31 March 
2015.
Inventories of US$ 10,318,743 (previous year: US$ 10,061,574) were capitalised as part of exploration and 
evaluation assets and development assets. ANNUAL REPORT 2014–15
40
11. OTHER CURRENT ASSETS
 31 March 2015 31 March 2014
Prepayments for
– debt raising cost 1,011,333 363,762
– others 306,364 44,883
Total 1,317,697 408,645
12. CASH AND CASH EQUIVALENTS
 31 March 2015 31 March 2014
Cash at banks in current accounts 12,251,533 977,028
Total 12,251,533 977,028
The Group only deposits cash surpluses with major banks of high quality credit standing.
13. EQUITY
Authorised share capital
The total authorised share capital of the Company is GBP 5,000,000 divided into 500,000,000 shares of 
GBP 0.01 each. The total number of shares issued by the Company as at 31 March 2015 is 182,973,924 
(previous year: 182,973,924).
For all matters submitted to vote in the shareholders meeting of the Company, every holder of ordinary 
shares, as reflected in the records of the Company on the date of the shareholders’ meeting has one vote 
in respect of each share held.
All shareholders are equally eligible to receive dividends and the repayment of capital in the event of 
liquidation of the individual entities of the Group. 
Additional paid in capital
Additional paid-in capital represents excess over the par value of share capital paid in by shareholders in 
return for the shares issued to them, recorded net of expenses incurred on issue of shares. 
Currency translation reserve
Currency translation reserve represents the balance of translation of the entities financial statements into 
US$ until 30 November 2010 when its functional currency was assessed as GBP . Subsequent to 1 December 
2010, the functional currency of Indus Gas was reassessed as US$.
Merger reserve
The balance on the merger reserve represents the fair value of the consideration given in excess of the 
nominal value of the ordinary shares issued in an acquisition made by the issue of shares of subsidiaries 
from other entities under common control.
Share option reserve
The amount of share option reserve represents the accumulated expense recognised by the company 
in its consolidated statement of comprehensive income on account of share based options given by the 
Company.
Retained earning
Retained earnings include current and prior period retained profits. ANNUAL REPORT 2014–15
41
14. LONG TERM DEBT FROM BANKS
Maturity 31 March 2015 31 March 2014
Non-current portion of long term debt 2018/2024 200,293,945 85,266,117
Current portion of long term debt from banks 18,389,976 17,301,889
Total  218,683,921 102,568,006
Current interest rates are variable and weighted average interest for the year was 5.62 per cent per annum 
(previous year: 6.02 per cent per annum). The fair value of the above variable rate borrowings are considered 
to approximate their carrying amounts. The maturity profile (undiscounted) is explained in note 29.
Interest capitalised on loans above have been disclosed in notes 6 and 7.
The term loans are secured by following:-
•	
First charge on all project assets of the Group both present and future, to the extent of SGL Field 
Development and to the extent of capex incurred out of this facility in the rest of RJ-ON/6 field.
•	
First charge on the current assets (inclusive of condensate receivable) of the Group to the extent of 
SGL field.
•	
First charge on the entire current assets of the SGL Field and to the extent of capex incurred out of this 
facility in the rest of RJON/6 field.
15. PROVISION FOR DECOMMISSIONING
Provision for 
decommissioning
Balance as at 1 April 2013 909,515
Increase in provision 170,431
Balance as at 31 March 2014 1,079,946
Increase in provision 201,916
Balance as at 31 March 2015 1,281,862
As per the PSC, the Group is required to carry out certain decommissioning activities on gas wells. The 
provision for decommissioning relates to the estimation of future disbursements related to the abandonment 
and decommissioning of gas wells. The provision has been estimated by the Group’s engineers, based on 
individual well filling and coverage. This provision will be utilised when the related wells are fully depleted. 
The majority of the cost is expected to be incurred within a period of next 9 years. The discount factor 
being the risk adjusted rate related to the liability is estimated to be 8 per cent for the year ended 31 March 
2015 (previous year: 8 per cent).
16. PAYABLE TO RELATED PARTIES
Related parties payable comprise of the following:
Maturity 31 March 2015 31 March 2014
Current
Liability payable to Focus On demand 23,446,172 96,783,891
Payable to directors On demand 44,171 63,914
23,490,343 96,847,805
Other than current
Borrowings from Gynia Holdings Ltd.* 120,288,834 112,947,262
120,288,834 112,947,262
Total 143,779,177 209,795,067 ANNUAL REPORT 2014–15
42
Liability payable to Focus 
Liability payable to Focus represents amounts due to them in respect of the Group’s share of contract costs, 
for its participating interest in Block RJ-ON/6 pursuant to the terms of Agreement for Assignment dated 
13 January 2006 and its subsequent amendments from time to time. 
The management estimates the current borrowings to be repaid on demand within twelve months from the 
statement of financial position date and these have been classified as current borrowings.
* Borrowings from Gynia Holdings Ltd. carries interest rate of 6.5 per cent per annum compounded 
annually. During the current year, the entire outstanding balance (including interest) was made subordinate 
to the loans taken from the banks (detailed in note 14) and therefore, is payable along with related interest 
subsequent to repayment of bank loan in year 2024. As at 31 March 2014, only US$ 52.6 million was 
subordinated to loans taken from banks.
Interest capitalised on loans above have been disclosed in notes 6 and 7.
17. EMPLOYEE COST
Costs pertaining to the employees of Focus have been included in the cost of sales and administrative 
expenses in the consolidated statement of comprehensive income amounting to US$ 352,458 (previous 
year US$ 286,366) and US$ 604,906 (previous year US$ 444,466) respectively. Cost pertaining to the 
employees of the Group have been included under administrative expense is US$ 728,605 (previous year 
US$ 315,914).
18. FOREIGN CURRENCY EXCHANGE (LOSS)/GAIN, NET
The Group has recognised the following in the profit or loss on account of foreign currency fluctuations:
  31 March 2015 31 March 2014
(Loss)/gain on restatement of foreign currency monetary 
receivables and payables
(1,330) 1,423
(Loss)/gain arising on settlement of foreign currency 
transactions and restatement of foreign currency balances 
arising out of Oil block operations 
(15,139) 77,466
Total (16,469) 78,889
19. OPERATING LEASES
Lease payments capitalised under exploration and evaluation assets and development/production assets 
during the year ended 31 March 2015 amount to US$ 38,203,891 (previous year US$ 40,284,032). No 
sublease payments or contingent rent payments were made or received. No sublease income is expected 
as all assets held under lease agreements are used exclusively by the Group. All the operating leases of 
the Group can be cancelled and there are no future minimum payments for the existing operating leases. 
The terms and conditions of these operating leases do not impose any significant financial restrictions  
on the Group. 
20. SHARE BASED PAYMENT
The Company maintains an equity settled share-based payment scheme adopted and approved by the 
directors on 29 May 2008. Presently, the Company has approved three schemes for the Directors, Consultant 
and Nominated Advisor known as the “Directors’ option agreements”, “Advisors Option agreement” and 
“Arden option deed”, respectively. The Company has no legal or constructive obligation to repurchase 
or settle the options. In accordance with the Plan, upon vesting, the stock options will be settled by the 
issuance of new shares on payment of the exercise price. ANNUAL REPORT 2014–15
43
The total amount to be expensed over the vesting period is determined by reference to the fair value of 
the options granted. The fair values of options granted were determined using the Black Scholes option 
pricing model that takes into account factors specific to the share incentive plans along with other external 
inputs. Vesting of these options have completed in earlier years and there is no expense in respect of these 
options during the years ended 31 March 2015 and 2014. 
The total outstanding and exercisable share options and weighted average exercise prices for the various 
categories of option holders during the reporting periods are as follows:
Share options granted to Directors and Advisors 
All the options granted to the Directors and Advisors are fully vested in earlier years. During the year ended 
31 March 2015, no option was exercised. The outstanding balance and exercisable share options as at 
31 March 2015 and 31 March 2014 were 180,000 shares having a weighted average price of US$ 1.64 per 
option. These options have expired post year end in June 2015. 
Share options granted to Arden Partners
There was no movement in the outstanding options under this category during the year ended 31 March 
2015 as the Share options granted to Arden Partners on 28 May 2008 are fully vested and consequently, 
there is no accounting implication during the reported period. The outstanding balance and exercisable 
share options granted to Arden Partners as of 31 March 2015 and 31 March 2014 was 76,220 having a 
weighted average price of US$ 1.64 per option. These options have expired post year end in June 2015.
21. EARNINGS PER SHARE
The calculation of the basic earnings per share is based on the earnings attributable to ordinary shareholders 
divided by the weighted average number of shares in issue during the year.
Calculation of basic and diluted earnings per share is as follows:
31 March 2015 31 March 2014
Profits attributable to shareholders of Indus Gas Limited, for 
basic and dilutive
16,244,591 11,771,933
Weighted average number of shares (used for basic earnings 
per share)
182,973,924 182,973,924
No of equivalent shares in respect of outstanding options 143,942 55,454
Diluted weighted average number of shares (used for
Diluted earnings per share)
183,117,866 183,029,378
Basic earnings per share 0.09 0.06
Dilutive earnings per share 0.09 0.06 ANNUAL REPORT 2014–15
44
22. RELATED PARTY TRANSACTIONS
The related parties for each of the entities in the Group have been summarised in the table below: 
Nature of the relationship Related party’s name
  I. Holding Company Gynia Holdings Ltd.
 II. Ultimate Holding Company
Multi Asset Holdings Ltd. (Holding Company of 
Gynia Holdings Ltd.)
III. Enterprises over which Key Management 
Personnel (KMP) exercise control (with whom 
there are transactions)
Focus Energy Limited
Disclosure of transactions between the Group and related parties and the outstanding balances as at 
31 March 2015 and 31 March 2014 is as under:
Transactions with holding company
Particulars 31 March 2015 31 March 2014
Transactions during the year with the holding company
Interest 7,341,572 6,893,495
Balances at the end of the year
Total payable* 120,288,834 112,947,262
*including interest 
Transactions with KMP and entity over which KMP exercise control
Particulars 31 March 2015 31 March 2014
Transactions during the year
Remuneration to KMP
	 •	 Short	term	employee	benefits 725,655 315,914
Total 725,655 315,914
Entity over which KMP exercise control
Cost incurred by Focus on behalf of the Group in respect of 
the Block
65,876,451 68,524,909
Remittances to Focus 138,690,000 26,774,123
Expenses reimbursed 524,170 812,786
Balances at the end of the year
Total payable* 23,446,172 96,783,891
*including interest
Directors’ remuneration
Directors’ remuneration is included under administrative expenses, evaluation and exploration assets or 
development assets in the consolidated financial statements allocated on a systematic and rational manner.
Remuneration by director is also separately disclosed in the directors’ report on page 12.
23. SEGMENT REPORTING
The Chief Operating Decision Maker, Chief Executive Officer of the Group, reviews the business as one 
operating segment being the extraction and production of gas. Hence, no separate segment information 
has been furnished herewith. ANNUAL REPORT 2014–15
45
All of the non-current assets other than financial instruments and deferred tax assets (there are no 
employment benefit assets and rights arising under insurance contracts) are located in India and amounted 
to US$ 483,800,708 (previous year: US$ 408,583,136).
The Group sells natural gas and its by product condensate gas. The natural gas is supplied to a single 
customer, GAIL, in a single geographical segment, being India. Sale of by product is not significant to be 
classified as a separate reportable segment.
24. COMMITMENTS AND CONTINGENCIES
The Group has no contingencies as at 31 March 2015 (previous year Nil).
The Group has no commitments as at 31 March 2015 (previous year Nil).
25. RECLASSIFICATION
The statement of financial position as at 31 March 2014 has been restated due to reclassification of tax 
asset from current classification to non-current. The third statement of consolidated financial position has 
not been presented since the error pertains to year ended 31 March 2014 and does not have any material 
impact on the year(s) prior to that.
Detail of this reclassification is summarised below:
Statement of financial position – 
Particulars 31 March 2014 Reclassification
31 March 2014 
(Restated)
Current
Tax assets 726,511 (726,511) -
Non-current
Tax assets - 726,511 726,511
26. ACCOUNTING ESTIMATES AND JUDGEMENTS
In preparing consolidated financial statements, the Group’s management is required to make judgments 
and estimates that affect the reported amounts of assets and liabilities and the disclosure of contingent 
assets and liabilities at the date of the financial statements and the reported amounts of revenues and 
expenses during the reporting period. The judgments and estimates are based on management’s best 
knowledge of current events and actions and actual results from those estimates may ultimately differ.
Significant judgments applied in the preparation of the consolidated financial statements are as under:
Determination of functional currency of individual entities
Following the guidance in IAS 21 “The effects of changes in foreign exchange rates” the functional currency 
of each individual entity is determined to be the currency of the primary economic environment in which 
the entity operates. In the management’s view each of the individual entity’s functional currency reflects 
the transactions, events and conditions under which the entity conducts its business. The management 
believes that US$ has been taken as the functional currency for each of the entities within the Group. US$ 
is the currency in which each of these entities primarily generate and expend cash and also generate funds 
for financing activities.
Full cost accounting for exploration and evaluation expenditure
The Group has followed ‘full cost’ approach for accounting exploration and evaluation expenditure against 
the ‘successful efforts’ method. As further explained in Note 5.6 and 6, exploration and evaluation assets 
recorded using ‘full cost’ approach are tested for impairment prior to reclassification into development 
assets on successful discovery of gas reserves. ANNUAL REPORT 2014–15
46
Impairment of tangible assets
The Group follows the guidance of IAS 36 and IFRS 6 to determine when a tangible asset is impaired. 
This determination requires significant judgment to evaluate indicators triggering impairment. The Group 
monitors internal and external indicators of impairment relating to its tangible assets. The management has 
assessed that no such indicators have occurred or exists as at 31 March 2015 to require impairment testing 
of property, plant and equipment.
Estimates used in the preparation of the consolidated financial statements 
Useful life and residual value of tangible assets
The Group reviews the estimated useful lives of property, plant and equipment at the end of each annual 
reporting period. Specifically, production assets are depreciated on a basis of unit of production (UOP) 
method which involves significant estimates in respect of the total future production and estimate of 
reserves. The calculation of UOP rate of depreciation could be impacted to the extent that the actual 
production in future is different from the forecasted production. During the financial year, the directors 
determined that no change to the useful lives of any of the property, plant and equipment is required. The 
carrying amounts of property, plant and equipment have been summarised in note 7.
Recognition of provision for decommissioning cost
As per the PSC, the Group is required to carry out certain decommissioning activities on gas wells. The 
ultimate decommissioning costs are uncertain and cost estimates can vary in response to many factors 
including changes to relevant legal requirements, the emergence of new restoration techniques or 
experience at other production sites. The expected timing and amount of expenditure can also change, for 
example, in response to changes in reserves or changes in laws and regulations or their interpretation. As a 
result, there could be adjustments to the provisions established which would affect future financial results. 
The liabilities estimated in respect of decommissioning provisions have been summarised in note 15.
Impairment testing
As explained above, the management carried out impairment testing of property, plant and equipment 
of the Block on 19 November 2013 on submission of integrated declaration of commerciality report by 
Focus Energy Limited to the Directorate General of Hydrocarbons, ONGC, the Government of India and 
the Ministry of Petroleum and Natural Gas. An impairment loss is recognized for the amount by which 
the asset’s or cash generating unit’s carrying amount exceeds its recoverable amount. To determine the 
recoverable amount, management estimates expected future cash flows from the Block and determines a 
suitable interest rate in order to calculate the present value of those cash flows. In the process of measuring 
expected future cash flows management makes assumptions about future gross profits. These assumptions 
relate to future events and circumstances. In most cases, determining the applicable discount rate involves 
estimating the appropriate adjustment to market risk and the appropriate adjustment to asset-specific risk 
factors.
The recoverable amount was determined based on value-in-use calculations, basis gas reserves confirmed 
by an independent competent person. Selling price of the gas is based on existing selling price to GAIL 
which has been agreed for a period of three years which is expiring on September 2015 and henceforth, the 
prices would be reviewed periodically and reassessed mutually by the parties. The discount rate calculation 
is based on the Company’s weighted average cost of capital adjusted to reflect pre-tax discount rate and 
amounts to 10% p.a. Management believes that no reasonably possible changes in the assumptions may 
lead to impairment of property, plants and equipment and intangible assets of the Block. ANNUAL REPORT 2014–15
47
Deferred tax assets
The assessment of the probability of future taxable income in which deferred tax assets can be utilized is 
based on the management’s assessment, which is adjusted for specific limits to the use of any unused tax 
loss or credit. The tax rules in the jurisdictions in which the Group operates are also carefully taken into 
consideration. If a positive forecast of taxable income indicates the probable use of a deferred tax asset, 
especially when it can be utilized without a time limit, then deferred tax asset is usually recognized in full.
27. BASIS OF GOING CONCERN ASSUMPTION
The Group has current liabilities amounting to US$ 47,126,214 the majority of which is towards current 
portion of borrowings from banks and related parties, primarily to Focus. As at 31 March 2015, the amounts 
due for repayment within the next 12 months to banks are US$ 18,389,976, which the Group expects to 
meet from its internal generation of cash from operations. Further, the Group continues to widen the 
funding options available and has established a Multicurrency Medium Term Note (“MTN”) Programme 
with the SGX in Singapore for up to US$ 300 Million. Out of which, the Group has successfully placed SGD 
100 Million Senior Unsecured Notes as first tranche of the MTN Programme, subsequent to the year end. 
The net proceeds will be utilised towards further development expenditure on the Block. Depending upon 
the funding requirement and subject to potential availability of financing on reasonable terms, the Group 
may draw further tranches against this MTN Programme in future. Based on this, the consolidated financial 
statements have been prepared on the going concern basis.
28. CAPITAL MANAGEMENT POLICIES
The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going 
concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an 
optimal capital structure to reduce the cost of capital.
The Group manages the capital structure and makes adjustments to it in the light of changes in economic 
conditions and the risk characteristics of the underlying assets. The Group monitors capital on the basis of 
the gearing ratio. This ratio is calculated as net debt divided by total capital. 
Debt is calculated as total liabilities (including ‘current and non-current liabilities’ as shown in the 
consolidated Statement of Financial Position). Total equity is calculated as ‘equity’ as shown in the 
consolidated Statement of Financial Position plus total debt.
31 March 2015 31 March 2014
Total debt (A) 421,000,173 355,953,141
Total equity (B) 88,160,441 71,915,850
Total capital employed (A+B) 509,160,614 427,868,991
Gearing ratio 82.69 per cent 83.19 per cent
The gearing ratio has marginally reduced since the previous year due to proportionately greater increase in 
equity as compared to increase in the draw-down of loans from banks and related party to fund additional 
exploration, evaluation and development activities for the Group.
The Group is not subject to any externally imposed capital requirements. There were no changes in the 
Group’s approach to capital management during the year. ANNUAL REPORT 2014–15
48
29. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
A summary of the Group’s financial assets and liabilities by category are mentioned in the table below:
The carrying amounts of the Group’s financial assets and liabilities recognised at the end of the reporting 
period are as follows:
  31 March 2015 31 March 2014
Non-current assets
Loans and receivables
– Security deposits 6,225 885
Current assets 
Loans and receivables
– Trade receivables 5,330,484 7,847,404
– Cash and cash equivalents 12,251,533 977,028
Total financial assets under loans and receivables 17,588,242 8,825,317
Non-current liabilities 
Financial liabilities measured at amortised cost
– Long term debt from banks 200,293,945 85,266,117
– Payable to related parties 120,288,834 112,947,262
Current liabilities
Financial liabilities measured at amortised cost
– Current portion of long term debt from banks 18,389,976 17,301,889
– Current portion of payable to related parties 23,446,172 96,783,891
– Accrued expenses and other liabilities 168,809 126,478
Total financial liabilities measured at amortised cost 362,587,736 312,425,637
The fair value of the financial assets and liabilities described above closely approximates their carrying 
value on the statement of financial position date. 
Risk management objectives and policies
The Group finances its operations through a mixture of loans from banks and related parties and equity. 
Finance requirements such as equity, debt and project finance are reviewed by the Board when funds are 
required for acquisition, exploration and development of projects. 
The Group treasury functions are responsible for managing fund requirements and investments which 
includes banking and cash flow management. Interest and foreign exchange exposure are key functions of 
treasury management to ensure adequate liquidity at all times to meet cash requirements.
The Group’s principal financial instruments are cash held with banks and financial liabilities to banks and 
related parties and these instruments are for the purpose of meeting its requirements for operations. The 
Group’s main risks arising from financial instruments are foreign currency risk, liquidity risk, commodity 
price risk and credit risks. Set out below are policies that are used to manage such risks:
Foreign currency risk
The functional currency of each entity within the Group is US$ and the majority of its business is conducted 
in US$. All revenues from gas sales are received in US$ and substantial costs are incurred in US$. No 
forward exchange contracts were entered into during the year. ANNUAL REPORT 2014–15
49
Entities within the Group conduct the majority of their transactions in their functional currency other than 
finance lease obligation balances which are maintained in Indian Rupees and amounts of cash held in 
GBP. All other monetary assets and liabilities are denominated in functional currencies of the respective 
entities. The currency exposure on account of liabilities which are denominated in a currency other than 
the functional currency of the entities of the Group as at 31 March 2015 and 31 March 2014 is as follows: 
Functional 
currency
Foreign currency 31 March 2015 31 March 2014
Total exposure 62,406 89,424
Short term exposure US$ Great Britain pound 62,406 89,424
The Group’s currency exposure risk towards GBP is insignificant and accordingly the movement in foreign 
currency will not have a material impact on the consolidated financial statements.
Liquidity risk
Ultimate responsibility for liquidity risk management rests with the Board of Directors, which has established 
an appropriate liquidity risk management framework for the management of the Group’s short-, medium- 
and long-term funding and liquidity management requirements. The Group manages liquidity risk 
by maintaining adequate reserves, banking facilities and reserve borrowing facilities, by continuously 
monitoring forecast and actual cash flows, and by matching the maturity profiles of financial assets and 
liabilities.
The table below summaries the maturity profile of the Group’s financial liabilities based on contractual 
undiscounted payments for the liquidity analysis
On 
demand 1–3 months
3 months 
to 1 year 1–5 years 5+ years Total
31 March 2015
Non-interest bearing – 168,809 – – – 168,809
Variable interest rate liabilities 23,446,172 4,689,367 13,766,519 147,229,561 57,136,920 246,268,539
Fixed interest rate liabilities – – – – 120,288,834 120,288,834
23,446,172 4,858,176 13,766,519 147,229,561 177,425,754 366,726,182
On 
demand
1–3 months
3 months
 to 1 year 
1–5 years 5+ years Total
31 March 2014
Non-interest bearing – 126,478 – – – 126,478
Variable interest rate liabilities 96,783,891 4,857,924 14,273,906 58,573,526 26,076,167 200,565,414
Fixed interest rate liabilities – – – – 112,947,262 112,947,262
96,783,891 4,984,402 14,273,906 58,573,526 139,023,429 313,639,154 ANNUAL REPORT 2014–15
50
Interest rate risk
The Group’s policy is to minimize interest rate risk exposures on the borrowing from the banks and the 
sum payable to Focus Energy Limited. Interest rate on the sum payable to Focus Energy Limited is linked 
to actual interest incurred by Focus capped between 6.5 per cent and 10 per cent on the chargeable sum 
(as defined under amendment in agreement for assignment of participating interest). Borrowing from the 
Gynia Holdings Ltd. is at fixed interest rate and therefore, doesn’t expose the Group to risk from changes in 
interest rate. The Group is exposed to changes in market interest rates through bank borrowings at variable 
interest rates. Interest rate on US$ 110 million bank borrowing is 5 per cent plus LIBOR; on US$ 40 million 
bank borrowing is 4 per cent plus LIBOR and on US$ 180 million bank borrowing is 4.1 per cent plus LIBOR 
(detailed in note 14).
The Group’s interest rate exposures are concentrated in US$.
The analysis below illustrates the sensitivity of profit and equity to a reasonably possible change in interest 
rates. Based on volatility in interest rates in the previous 12 months, the management estimates a range 
of 50 basis points to be approximate basis for the reasonably possible change in interest rates. All other 
variables are held constant.
Interest rate
+0.50 per cent –0.50 per cent
31 March 2015
 1,694,864  (1,694,864)
31 March 2014 996,759 (996,759)
Since the loans are taken specifically for the purpose of exploration and evaluation, development and 
production activities and according to the Group’s policy the borrowing costs are capitalised to the cost of 
the asset and hence changes in the interest rates do not have any immediate adverse impact on the profit 
or loss. 
Commodity price risks
The Group’s share of production of gas from the Block is sold to GAIL. The price has been agreed for a 
period of three years which is expiring in September 2015 and henceforth, the same would be reviewed 
periodically and reassessed mutually by the parties. No commodity price hedging contracts have been 
entered into.
Credit risk
The Group has made short-term deposits of surplus funds available with banks and financial institutions of 
good credit repute and therefore, doesn’t consider credit risk to be significant. Other receivables such as 
security deposits and advances with related parties, do not comprise of a significant cumulative balance 
and thus do not expose the Group to a significant credit risk. The Group has concentration of credit risk 
as all the Group’s trade receivables are held with GAIL, its only customer. However, GAIL has a reputable 
credit standing and hence the Group does not consider credit risk in respect of these to be significant. 
None of the financial assets held by the Group are past due.
30. SUBSEQUENT EVENTS
Subsequent to year end 31 March 2015, the Company has established a Multicurrency Medium Term Note 
(“MTN”) Programme with the SGX in Singapore and raised SGD 100 million (refer Note 27 for details).  DIRECTORS
Peter Cockburn
Non-Executive Director, Chairman
Marc Holtzman
Non-Executive Director Executive Director, CFO
John Scott
Executive Director, CEO
Ajay Kalsi
COMPANY SECRETARY
Willow Trust Limited
L
Les Echelons, St Peter Port,
Guernsey GY1 2JF
Tel:  +44 1481 721500
Fax: +44 1481 721600
es Echelons Court,                                                                                                                                                                                                                 
AUDITORS
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LONDON REPRESENTATIVE OFFICE
Indus Gas Limited
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www.indusgas.com
d irECTOrS
a jay kalsi
Executive Director, CEO
COmpaNy SECrET ary
w illow Trust limited
Les Echelons Court,
Les Echelons, St Peter Port, 
Guernsey GY1 2JF
Tel:  +44 1481 721500 
Fax: +44 1481 721600
NOmiNaTEd adviSEr aNd Br OkEr
a rden partners pl C
125 Old Broad Street 
London EC2N 1AR 
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a udiTOrS
Grant Thornton limited
PO Box 313, Lefebvre House                                                
Lefebvre Street, St Peter Port 
Guernsey GY1 3TF
Tel: +44 1481 753400
Fax: +44 1481 753401
FiNaNCial pr
Bell pottinger
5th Floor, Holborn Gate 
330 High Holborn 
London WC1V 7QD
Tel: +44 20 3772 2500
CrEST SErviCE pr OvidEr
Computershare investor Services 
(Channel islands) limited
Queensway House, Hilgrove Street
St Helier, Jersey JE1 1ES
Tel: +44 (0) 1534 825230, +44 (0) 870 707 4040 
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r EGiSTErEd OFFiCE :
Les Echelons Court,
Les Echelons, St Peter Port, 
Guernsey GY1 2JF
Tel:  +44 1481 721500 
Fax: +44 1481 721600 
www.indusgas.com
peter Cockburn
Non-Executive Director, Chairman
Bruce mcNaught
Non-Executive Director
John Scott 
Executive Director, CFO