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Hardy Copy No. EE024430

GCA GAFFNEY, CLINE & ASSOCIATES

COMPETENT PERSON’S REPORT ON HARDY’S PETROLEUM INTERESTS

Prepared for

HARDY OIL AND GAS PLC

MARCH, 2011

The Americas Europe, Africa, FSU Asia Pacific and the Middle East 1300 Post Oak Blvd., Bentley Hall, Blacknest 80 Anson Road Suite 1000 Alton, Hampshire 31-01C Fuji-Xerox Towers Houston, Texas 77056 United Kingdom GU34 4PU Singapore 079907 Tel: +1 713 850 9955 Tel: +44 1420 525366 Tel: +65 6225 6951 Fax: +1 713 850-9966 Fax: +44 1420 525367 Fax: +65 6224 0842 email: [email protected] email: [email protected] email: [email protected] and at Argentina - Brazil - Kazakhstan - Russia - UAE - Australia www.gaffney-cline.com

Hardy EE024430

GCA TABLE OF CONTENTS

Page No.

INTRODUCTION ................................................................................................................................. 1 SUMMARY ............................................................................................................................................... 4 1. DISCUSSION ........................................................................................................................... 13 1.1 Cauvery Basin ............................................................................................................ 13

1.1.1 PY-3 Field (Hardy NWI 18%) ............................................................... 13 1.1.2 Block CY-OS/2 (Hardy NW1 75%, Operator) ................................ 21

1.2 Saurashtra Basin (west of Mumbai Offshore Basin) .......................................... 26 1.2.1 Block GS-01(Hardy NW1 10%) .................................................................. 30 1.2.1.1 Contingent Resources .................................................................... 30 1.2.1.2 Prospective Resources ................................................................... 34 1.3 Krishna Godavari Basin ........................................................................................... 36 1.3.1 Block D3 (Hardy NW1 10%) ....................................................................... 39 1.3.1.1 Contingent Resources .................................................................... 41 1.3.1.2 Prospective Resources ................................................................... 46 1.3.2 Block D9 (Hardy NW1 10%) ....................................................................... 52 1.4 Assam-Arakan Basin ............................................................................................................... 58 1.4.1 AS-ONN-2000/1 (Hardy NWI 10%) ........................................................ 61 2. ECONOMIC EVALUATION ................................................................................................ 64 2.1 Fiscal Systems ............................................................................................................. 64 2.2 Cost Assumptions .................................................................................................... 65 2.3 Oil Pricing ................................................................................................................... 65 2.4 NPV Results ............................................................................................................... 65 3. QUALIFICATIONS ................................................................................................................. 66 4. BASIS OF OPINION ............................................................................................................... 66 Tables 0.1 Summary of Licence Areas .................................................................................................... 6 0.2 Summary of Estimated Gross and Net Entitlement Oil Reserves as at 31st December, 2010 .................................................................................................... 6 0.3 Summary of Hardy Reference Pre-/Post-Tax Net Present Values as at 31st December, 2010 .................................................................................................... 7 0.4 PY-3 Gross Production and Cost Profiles ......................................................................... 7

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0.5 Summary of Gross and Net Gas Contingent Resources as at 31st December, 2010 .................................................................................................... 8 0.6 Summary of Gross and Net Gas Condensate Contingent Resources as at 31st December, 2010 .................................................................................................... 8 0.7 Summary of Gross and Net Gas Prospective Resources for Prospects as at 31st December, 2010 .................................................................................................... 9 0.8 Summary of Gross and Net Oil Prospective Resources for Prospects as at 31st December, 2010 .................................................................................................... 12 1.1 Well Ganesha-1: Summary of DST Results ....................................................................... 22 1.2 Summary of CY-OS/2 Gross and Net Gas Contingent Resources as at 31st December, 2010 .................................................................................................... 23 1.3 Ganesha-1: Summary Prospects Gross GIIP (BCF)......................................................... 24 1.4 Summary of Gross and Net Gas Prospective Resources for Prospects as at 31st December, 2010 .................................................................................................... 26 1.5 GS-01 Summary of Gross and Net Gas Contingent Resources as at 31st December, 2010 .................................................................................................... 33 1.6 GS-01 Summary of Gross and Net Gas Condensate Contingent Resources as at 31st December, 2010 .................................................................................................... 33 1.7 GS-01 Prospects – Summary of Gross GIIP (BCF) ......................................................... 35 1.8 Summary of GS-01 Gross and Net Gas Prospective Resources for Prospects as at 31st December, 2010 .................................................................................................... 36 1.9 Block D3: Summary of Gross GIIP for Discoveries as at 31st December, 2010 ...... 45 1.10 Block D3: Summary of Gross and Net Gas Contingent Resources

for Discoveries as at 31st December, 2010 ....................................................................... 45 1.11 Block D3: Summary of Gross GIIP for Prospects as at 31st December, 2010 ......... 50 1.12 Block D3: Summary of Gross and Net Gas Prospective Resources for Prospects as at 31st December, 2010 .................................................................................................... 51 1.13 Block D3: Summary of Gross GIIP for Leads as at 31st December, 2010 ................. 52 1.14 Block D3: Summary of Gross Unrisked Gas Prospective Resources for Leads as at 31st December, 2010 .................................................................................................... 52 1.15 Block D9: Summary of Gross GIIP for Prospects/Leads

as at 31st December, 2010 ................................................................................................... 55 1.16 Block D9: Summary of Unrisked Gross STOIIP for Prospects/Leads

as at 31st December, 2010 .................................................................................................... 55 1.17 Block D9: Summary of Gross and Net Gas Prospective Resources

for Prospects as at 31st December, 2010 .......................................................................... 56 1.18 Block D9: Summary of Gross and Net Oil Prospective Resources

for Prospects as at 31st December, 2010 .......................................................................... 57 1.19 Block D9: Summary of Gross Unrisked Gas Prospective Resources

for Leads as at 31st December, 2010 .................................................................................. 57 1.20 Block D9: Summary of Gross Unrisked Oil Prospective Resources

for Leads as at 31st December, 2010 .................................................................................. 58 1.21 AS-ONN-2000/1: Summary of Gross STOIIP for Leads as at

31st December, 2010 .............................................................................................................. 63 1.22 AS-ONN-2000/1: Summary of Gross and Net Oil Prospective Resources

for Leads as at 31st December, 2010 .................................................................................. 63 2.1 Pre- and Post-Tax Net Present Values Net to Hardy’s Reserves

as at 31st December, 2010 (U.S.$ MM) .............................................................................. 65

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Page No.

Figures 0.1 Location Map of Hardy’s Interests in India ....................................................................... 2 1.1 Location of PY-3 Field and Block CY-OS/2, Offshore Cauvery Basin, India ........... 15 1.2 Cauvery Basin Lithostratigraphic Column ........................................................................ 16 1.3 PY-3 Pay Top Structure Map with OWC @3,505 m SS ............................................... 17 1.4 PY-3 Pay Top Structure Map _Volumetric Polygons ...................................................... 18 1.5 PY-3 Field Production Performance and Forecast .......................................................... 20 1.6 CY-OS/2 Prospect Location Map ........................................................................................ 25 1.7 GS-01 Block Location ............................................................................................................. 27 1.8 Offshore Mumbai Basin Lithostratigraphic Column ........................................................ 28 1.9 Trap Styles in the Mumbai Basin .......................................................................................... 29 1.10 GS-OSN-1 Map ........................................................................................................................ 31 1.11 GS-01 3D Depth Structure Map at Top Bassein Formation ......................................... 32 1.12 Block GS-01 Seismic Line through the B-1 and A-1 Locations .................................... 34 1.13 Location Map Showing D3 and D9 Licences .................................................................... 37 1.14 Blocks D3/D9 Cenozoic Stratigraphy ................................................................................. 38 1.15 D3 Prospect and Lead Map ................................................................................................... 39 1.16 Surface Geochemical Evidence for Thermogenic Hydrocarbons ................................ 40 1.17 Wireline Log Responses at W1 Discovery ....................................................................... 42 1.18 Revised Sand 1 Amplitude Map (Main Segment) .............................................................. 43 1.19 Lack of Connectivity between Well -A1 and Prospect AP1 ......................................... 44 1.20 Seismic Section through the ‘Q’ Leads ............................................................................... 47 1.21 Seismic Section along the MMI Prospect with Potential Channels .............................. 48 1.22 D9 Prospect and Lead Location Map ................................................................................. 53 1.23 Geomorphology in Pliocene D9 revealed by Seismic Attributes ................................ 54 1.24 Oil Fields South of Brahmaputra River AS-ONN-2000/1 ............................................. 59 1.25 Stratigraphic Column Assam-Arakan Basin ....................................................................... 60 1.26 Seismic Line AS-17-08 in Assam Block .............................................................................. 61 1.27 AS-ONN-2000/1 Prospect and Lead Location Map Sylhet Formation

Time Structure Map ................................................................................................................ 62

Appendices I. Glossary II. SPE/WPC/AAPG/SPEE, Petroleum Resources Management System Definitions and

Guidelines

Bentley Hall Blacknest, Alton Hampshire GU34 4PU United Kingdom

Telephone: +44 (0) 1420 525366 Facsimile: +44 (0) 1420 525367

email: [email protected] www.gaffney-cline.com

Gaffney, Cline & Associates Ltd Technical and Management Advisers to the Petroleum Industry Internationally Since 1962

Registered London No. 1122740

UNITED KINGDOM UNITED STATES SINGAPORE AUSTRALIA ARGENTINA UAE RUSSIA KAZAKHSTAN

MIH/EE024430/cxd 11th March, 2011 The Directors, Hardy Oil and Gas plc, Lincoln House, 37-143 Hammersmith Road, London, W14 0QL Dear Sirs,

COMPETENT PERSON’S REPORT (CPR) ON HARDY’S PETROLEUM INTERESTS INTRODUCTION

In accordance with the instruction letter of Hardy Oil and Gas plc (Hardy) dated 16th November, 2010 Gaffney, Cline & Associates Ltd (GCA) has reviewed and audited the petroleum interests owned by Hardy (Figure 0.1). These assets include producing properties, potential developments, discoveries and duly licensed exploration interests. Hardy has made available to GCA a data-set of technical information, including geological, geophysical, and engineering data and reports, together with financial data and the fiscal and contractual terms applicable to each of the assets. GCA has also had meetings and discussions with Hardy technical and managerial personnel. In carrying out this review GCA has relied on the accuracy and completeness of the information received from Hardy.

GCA has not been requested to perform a site visit, nor has GCA considered this necessary for the purposes of this CPR.

GCA’s review and audit involved reviewing the relevant interpretations and assumptions made by

Hardy or others in preparing estimates of reserves or resources. We carried out procedures necessary to enable us to render an opinion on the appropriateness of the methodologies employed, adequacy and quality of the data relied upon, the depth and thoroughness of the reserves and resources estimation process.

Industry Standard abbreviations are contained in the attached Appendix I Glossary, some or all of which may have been used in this report. In this report GCA uses the Petroleum Resources Management System (SPE PRMS) published by the Society of Petroleum Engineers/World Petroleum Congresses/ American Association of Petroleum Geologists/Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) in March, 2007 as the basis for its classification and categorization of hydrocarbon volumes. An abbreviated form of the SPE PRMS is appended as Appendix II.

Hardy 2 EE024430

GCA Gaffney, Cline & Associates

FIGURE 0.1

LOCATION MAP OF HARDY’S INTERESTS IN INDIA

MaduraiMaduraiMaduraiMaduraiMaduraiMaduraiMaduraiMaduraiMadurai

MangaluruMangaluruMangaluruMangaluruMangaluruMangaluruMangaluruMangaluruMangaluru BengaluruBengaluruBengaluruBengaluruBengaluruBengaluruBengaluruBengaluruBengaluru

CochinCochinCochinCochinCochinCochinCochinCochinCochin

ChennaiChennaiChennaiChennaiChennaiChennaiChennaiChennaiChennai

MumbaiMumbaiMumbaiMumbaiMumbaiMumbaiMumbaiMumbaiMumbai

PunePunePunePunePunePunePunePunePune

PanajiPanajiPanajiPanajiPanajiPanajiPanajiPanajiPanaji

HyderabadHyderabadHyderabadHyderabadHyderabadHyderabadHyderabadHyderabadHyderabadVishakhapatnamVishakhapatnamVishakhapatnamVishakhapatnamVishakhapatnamVishakhapatnamVishakhapatnamVishakhapatnamVishakhapatnam

achiachiachiachiachirachirachirachiachi

AhmadabadAhmadabadAhmadabadAhmadabadAhmadabadAhmadabadAhmadabadAhmadabadAhmadabad

DamanDamanDamanDamanDamanDamanDamanDamanDaman

NagpurNagpurNagpurNagpurNagpurNagpurNagpurNagpurNagpur

BhopalBhopalBhopalBhopalBhopalBhopalBhopalBhopalBhopal RanchiRanchiRanchiRanchiRanchiRanchiRanchiRanchiRanchi

KhulnaKhulnaKhulnaKhulnaKhulnaKhulnaKhulnaKhulnaKhulna

BhubaneshwarBhubaneshwarBhubaneshwarBhubaneshwarBhubaneshwarBhubaneshwarBhubaneshwarBhubaneshwarBhubaneshwar

ImphalImphalImphalImphalImphalImphalImphalImphalImphal

AgartalaAgartalaAgartalaAgartalaAgartalaAgartalaAgartalaAgartalaAgartala

ChittagongChittagongChittagongChittagongChittagongChittagongChittagongChittagongChittagong

JaipurJaipurJaipurJaipurJaipurJaipurJaipurJaipurJaipur LucknowLucknowLucknowLucknowLucknowLucknowLucknowLucknowLucknow

VaranasiVaranasiVaranasiVaranasiVaranasiVaranasiVaranasiVaranasiVaranasi

GangtokGangtokGangtokGangtokGangtokGangtokGangtokGangtokGangtok

SaidpurSaidpurSaidpurSaidpurSaidpurSaidpurSaidpurSaidpurSaidpurPatnaPatnaPatnaPatnaPatnaPatnaPatnaPatnaPatna

ItanagarItanagarItanagarItanagarItanagarItanagarItanagarItanagarItanagar

KohimaKohimaKohimaKohimaKohimaKohimaKohimaKohimaKohimaShillongShillongShillongShillongShillongShillongShillongShillongShillong

ColomboColomboColomboColomboColomboColomboColomboColomboColombo

New DelhiNew DelhiNew DelhiNew DelhiNew DelhiNew DelhiNew DelhiNew DelhiNew Delhi

KathmanduKathmanduKathmanduKathmanduKathmanduKathmanduKathmanduKathmanduKathmandu

I N D I A

D9

D3

CY-OS/2PY-3 Field

GS-01

Sri Lanka

nnn

IndiaIndiaIndiaIndiaIndiaIndiaIndiaIndiaIndia

NepalakistanakistanakistanPakistanPakistanPakistanPakistanPakistanPakistan

B a yB a yB a yB a yB a yB a yB a yB a yB a yo fo fo fo fo fo fo fo fo f

B e n g a lB e n g a lB e n g a lB e n g a lB e n g a lB e n g a lB e n g a lB e n g a lB e n g a l

Bhutan

Myanmar

AndamanAndamanAndamanAndamanAndamanAndamanAndamanAndamanAndamanSeaSeaSeaSeaSeaSeaSeaSeaSea

BangladeshBangladeshBangladeshBangladeshBangladeshBangladeshBangladeshBangladeshBangladesh

0 500 km

Hardy Block Interests

Source: GCA/Petroview

Bay of Bengal

AS-ONN-2000/1

Hardy 3 EE024430


Reserves are those quantities of petroleum that are anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions. Reserves must further satisfy four criteria: they must be discovered, recoverable, commercial and remaining (as of the evaluation date) based on the development project(s) applied. Reserves are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by development and production status. All categories of Reserve volumes quoted herein have been determined within the context of an economic limit test (pre-tax and exclusive of accumulated depreciation amounts) assessment prior to any Net Present Value analysis.

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be

potentially recoverable from known accumulations, but the applied project(s) are not yet considered mature enough for commercial development due to one or more contingencies. Contingent Resources may include, for example, projects for which there are currently no evident viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

It must be appreciated that the Contingent Resources reported herein are unrisked in terms of

economic uncertainty and commerciality. Prospective Resources are those quantities of petroleum that are estimated, as of a given date, to

be potentially recoverable from undiscovered accumulations by application of future development projects. Prospective Resources have both an associated chance of discovery and a chance of development. Prospective Resources are further subdivided in accordance with the level of certainty associated with recoverable estimates assuming their discovery and development and may be sub-classified based on project maturity. Prospective Resources include Prospects and Leads. Prospects are features that have been sufficiently well defined, on the basis of geological and geophysical data, to the point that they are considered drillable. Leads, on the other hand, are not sufficiently well defined to be drillable, and need further work and/or data. In general, Leads are significantly more risky than Prospects and therefore are not suitable for explicit quantification.

Prospective Resource volumes are presented as unrisked. It must be appreciated that Prospective Resources are risk assessed only in the context of applying the stated 'Geological Chance of Success' (GCoS), a percentage which pertains to the percentage probability of achieving the status of a Contingent Resource (where the GCoS is unity). This dimension of risk assessment does not incorporate the considerations of economic uncertainty and commerciality.

Proved, Proved plus Probable and Proved plus Probable plus Possible Reserves net to Hardy are

quoted as Net Entitlement Reserves reflecting the terms of the applicable Production Sharing Contracts (PSCs). Contingent Resources are presented at a gross field level and a net working interest level, as it is not possible to estimate net entitlements under the relevant PSCs.

It must be clearly understood that any determination of resources volumes, particularly involving continuing field development, will be subject to significant variations over short periods of time as new information becomes available and perceptions change. Not only are such estimates of Reserves and Contingent and Prospective Resources based on that information which is currently available, but such estimates are also subject to uncertainties inherent in the application of judgmental factors in interpreting such information. Contingent and Prospective Resources quantities should not be confused with those quantities that are associated with Reserves due to the additional risks involved. Those quantities that might actually be recovered may differ significantly from the estimates presented herein. A possibility exists that the accumulations and prospects will not result in successful discovery and development, in which case there could be no positive potential present worth.

Hardy 4 EE024430


It should be clearly noted that the reference Net Present Values (NPVs) of future revenue potential of a petroleum property, such as those discussed in this report, do not represent GCA’s perception of the market value of that property, or any interest in it. In assessing a likely market value, it would be necessary to take into account a number of additional factors including: reserves risk (i.e. that Proved and or Probable Reserves may not be realised within the anticipated timeframe for their exploitation); perceptions of economic and sovereign risk; potential upside, such as in this case exploitation of reserves beyond the Proved and the Probable level; other benefits, encumbrances or charges that may pertain to a particular interest and the competitive state of the market at the time. GCA has explicitly not taken such factors into account in deriving the reference NPVs presented herein. GCA is an energy consultancy specialising in independent petroleum advice on resource evaluation and economic analysis. In the preparation of this report, GCA has maintained, and continues to maintain, a strict consultant-client relationship with Hardy. The management and employees of GCA have been, and continue to be, independent of Hardy in the services they provide to the company including the provision of the opinion expressed in this review. Furthermore, the management and employees of GCA have no interest in any assets or share capital of Hardy, or in the promotion of the company. This report must only be used for the purpose for which it was intended. SUMMARY Hardy has interests in a number of assets in India that comprise production, potential development, discoveries and exploration. Hardy’s Indian assets and the pertinent Net Working Interest (NWI) fractions are comprised of the following: PY-3 producing oil asset, located in the CY-OS-90/1 Production Licence sub-block of CY-OS/2 in

the Cauvery Basin, offshore Tamil Nadu in South-Western India (Hardy NWI 18%); Block CY-OS/2, located in the Cauvery Basin, offshore Tamil Nadu (Hardy NWI 75%); Block GS-OSN-2000/1 (NELP II), located in the Bombay offshore Basin, to the West and North

West of the ONGC operated Bombay High Field (Hardy NWI 10%). Also known as GS-01; Block KG-DWN-2003/1 (or D3) (NELP V), in the offshore Krishna-Godavari Basin due west and

some 50 km inshore of Reliance's 2003 gas discoveries in Block KG-DWN-98/3 (Hardy NWI 10%);

Block KG-DWN-2001/1(or D9) (NELP III) in the offshore Krishna-Godavari Basin (Hardy NWI 10%), adjacent to the Reliance concession mentioned above; and

Assam Block (AS-ONN-2000/1), located onshore in the North East part of India in the Assam-Arakan Basin, immediately north of the Brahmaputra River and south of the Eastern Himalaya (Hardy NWI 10%).

These concession areas are all shown on the regional location map, Figure 0.1. A summary of

licence areas and water depth ranges (where appropriate) is given in Table 0.1. GCA has conducted its review on the basis of the technical and commercial information made

available by Hardy as well as studies and assessments performed by the operators, other third parties, other information available from the Public domain and, in some cases, has derived its own estimates of Reserves, Contingent Resources and Prospective Resources where appropriate.

GCA has not visited the PY-3 Field production facilities and cannot, therefore, attest to the

reliability or integrity of these facilities.

The technical and economic conclusions presented herein are based on the technical and commercial information provided and represent GCA’s opinions as of the effective date of

Hardy 5 EE024430


31st December, 2010. The conclusions are estimates based upon professional geoscience and engineering judgment and they may be subject to future revisions as additional information becomes available. Reserves Summary

The "Proved", "Proved plus Probable" and "Proved plus Probable plus Possible" Reserves attributed to Hardy's interests in India as at 31st December, 2010 are for the producing field PY-3 as summarised in Table 0.2. All categories of Reserve volumes quoted herein have been determined within the context of an economic limit test. Net Present Value Summary Net Present Values (NPVs) have been attributed to the ‘Proved’, the ‘Proved plus Probable’ and the ‘Proved plus Probable plus Possible’ Reserves. Pre/Post-Tax NPVs are summarised in Table 0.3 based on GCA’s 1Q 2011 Brent price scenario. All NPVs quoted are those exclusively attributable to Hardy's net entitlement interests in the property reviewed. Production and Forecast Forecasts of gross oil production and costs are summarised in Table 0.4. Resource Summary

Apart from the producing assets, Hardy holds licences with discoveries and in a number of

exploration areas. GCA audited the estimates of Contingent Resources as of 31st December, 2010 and these are discussed in Section 1.1.2 (CY-OS/2), Section 1.2.1 (GS-01/B1 area) and Section 1.3.2 (Block D3) of this report. See Table 0.5.

In addition, a consideration has been made as to Hardy’s Prospective Resources that may be attributed to a number of undrilled Prospects, together with the associated geological chance of success (GCoS). Further, a significant number of Leads have been acknowledged in Blocks D-3 and D-9 in the emerging petroleum province of the continental slope off India’s eastern coast. The materiality of this potential will evolve through identification and subsequent maturation of Leads into “drillable Prospects”. The estimates of Hardy’s Prospective Resources as of 31st December, 2010 are shown in Tables 0.6 and 0.8. Exploration Potential Hardy recognizes that the exploration of D3 and D9 merits sequence stratigraphic analysis to better define the plays. This play analysis approach is being used to determine depositional systems and consequently the distribution of lithofacies within a chronostratigraphic envelope to give a better understanding of reservoir distribution and allow a more effective evaluation of existing prospectivity. Placing Leads in a play context will facilitate ranking in terms of GCoS. GCA endorses this approach and postulates that additional Leads to those currently identified by Hardy may be generated. This work is already in progress in Block D3.

Hardy 6 EE024430


TABLE 0.1

SUMMARY OF LICENCE AREAS

Field/Block Contract Operator Hardy NWI

%

Permit/PSC Granted Date

Permit/PSC Expiry Date

Block Area (km2)

Water Depth

(m) PY-3 CY-OS 90/1 Hardy 18 Dec, 1994 Dec, 2019 81 40 - 450 CY-OS/2 CY-OS/2 Hardy 75 Nov, 1996 Mar, 2007 859 50 - 900

GS-01 GS-OSN-

2000/1 Reliance 10 Jul, 2001 May, 2010 8,841 80 - 150

D9 KG-DWN-2001/1

Reliance 10 Feb, 2003 July, 2011 11,850 2,300-3,100

D3 KG-DWN-2003/1

Reliance 10 Sep, 2005 Sep, 2013 3,288 400-2,100

Assam AS-ONN-2000/1

Reliance 10 Jan, 2008 Jan, 2015 5,754 onshore

Notes: 1. CY-OS/2 permit extension is pending with the Ministry of Petroleum and Natural Gas, Government of India (MOPNG,

GOI) regarding the discovery type. 2. In the event of a commercial development of a discovery, ONGC has the option to back-into the CY-OS/2 licence at

an interest of 30%. 3. The GS-01 joint venture has elected not to enter into exploration phase II and is currently retaining an interest in the

block in accordance with the development provisions of the PSC. The retained area comprises 5,890 km2. 4. Phase-I exploration period in D9 has been extended to July, 2011. 5. In 2010 the GOI adopted a drilling moratorium for deepwater exploration licences providing for a three year extension

to 31 December 2020. Hardy’s D9 and D3 exploration blocks are entitled to the relief provided for in the moratorium.

TABLE 0.2

SUMMARY OF ESTIMATED GROSS AND NET ENTITLEMENT OIL RESERVES

AS AT 31st DECEMBER, 2010

Area

Gross Oil Reserves MMBbl

Hardy Interest

Net Entitlement Reserves MMBbl

Proved Proved

plus Probable

Proved plus

Probable plus

Possible

Proved Proved

plus Probable

Proved plus Probable

plus Possible

PY-3 2.5 15.1 21.4 18% 0.4 2.1 2.9 Note: 1. Net Entitlements are Reserves based on Hardy’s entitlement to Cost Oil plus share of Profit Oil.

Hardy 7 EE024430


TABLE 0.3

SUMMARY OF HARDY REFERENCE PRE-/POST-TAX NET PRESENT VALUES AS AT 31st DECEMBER, 2010

Asset Reserves Category

Pre-Tax NPVs Net to Hardy (U.S.$ MM)

Post-Tax NPVs Net to Hardy (U.S.$ MM)

7.5% 10.0% 12.5% 7.5% 10.0% 12.5%

PY-3

Proved 12.29 12.02 11.77 12.29 12.02 11.77

Proved plus Probable 65.95 60.55 55.82 43.47 39.86 36.72

Proved plus Probable plus

Possible 97.89 88.59 80.54 57.72 51.79 46.69

Notes: 1. All cash flows are discounted on a mid-year basis to 31st December, 2010; 2. Post-Tax NPVs include a tax loss position as at 31st December, 2010 of U.S.$24.6 MM as advised by Hardy. 3. Pre-Tax NPVs are equivalent to Post-Tax NPVs for Proved Reserves due to tax losses carried forward from

31st December, 2010.

TABLE 0.4

PY-3 GROSS PRODUCTION AND COST PROFILES

Year

Proved Proved plus Probable Proved plus Probable plus Possible Oil

Production MBbl

CAPEX U.S.$ MM

OPEX U.S.$ MM

Oil Production

MBbl

CAPEX U.S.$ MM

OPEX U.S.$ MM

Oil Production

MBbl

CAPEX U.S.$ MM

OPEX U.S.$ MM

2011 1,151.5 - 35 1,151.5 - 35 1,151.5 - 35

2012 802.9 - 37 2,156.4 162 37 2,156.4 162 37

2013 557.6 - 37 2,981.5 - 45 4,039.5 162 45

2014 - - - 2,205.6 - 45 4,010.8 - 45

2015 - - - 1,648.9 - 45 2,771.2 - 45

2016 - - - 1,286.5 - 45 2,005.1 - 45

2017 - - - 1,068.0 - 45 1,595.0 - 45

2018 - - - 939.4 - 45 1,364.5 - 45

2019 - - - 852.2 - 45 1,205.6 - 45

2020 - - - 780.6 - 45 1,085.8 - 45

2021 - - - - - - - - -

2022 - - - - - - - - -

Total MBbl

2,512.0 - 109 15,070.5 162 434 21,385.4 324 432

Notes: 1. Costs are in U.S.$ 2011. 2. Production is reported in annual quantities.

Hardy 8 EE024430


TABLE 0.5

SUMMARY OF GROSS AND NET GAS CONTINGENT RESOURCES AS AT 31st DECEMBER, 2010

Gross Contingent Resources

BCF

Hardy Interest

(%)

Net Hardy Contingent Resources

BCF

1C 2C 3C 1C 2C 3C

GS-01/ B1area 50.5 83.0 133.2 10 5.1 8.3 13.3 Total GS-01 50.5 83.0 133.2 10 5.1 8.3 13.3 CY-OS/2- Ganesha-1 69.1 130.0 222.5 75 51.8 97.5 166.9 Total CY-OS/2 69.1 130.0 222.5 75 51.8 97.5 166.9 D3 / W1 Pliocene 101.5 162.4 258.3 10 10.2 16.2 25.8 Total D3 / W1 Pliocene 101.5 162.4 258.3 10 10.2 16.2 25.8 D3 / A1 Pleistocene Sand 0 28.0 113.0 274.0 10 2.8 11.3 27.4 D3 / A1 Pleistocene Sand 1 33.0 97.0 209.0 10 3.3 9.7 20.9 Total D3 / A1 61.0 210.0 483.0 10 6.1 21.0 48.3 D3 / B1 Pleistocene Sand 2 (Southern) 57.0 146.0 316.0 10 5.7 14.6 31.6

D3 / B1 Well Pliocene Sand 27.0 67.0 125.0 10 2.7 6.7 12.5 Total D3 / B1 84.0 213.0 441.0 10 8.4 21.3 44.1 D3 / R1 Sand 1 (Miocene) 15.0 21.0 28.0 10 1.5 2.1 2.8 D3 / R1 Sand 2 (Miocene) 30.0 38.0 49.0 10 3.0 3.8 4.9 D3 / R1 Sand 3 (Miocene) 25.0 39.0 55.0 10 2.5 3.9 5.5 Total D3 / R1 70.0 98.0 132.0 10 7.0 9.8 13.2 Total D3 316.5 683.4 1314.3 10 31.7 68.3 131.4 Total 436.1 896.4 1670 - 88.6 174.1 311.6 Notes: 1. The Net Hardy Contingent Resources on this table are only indications of Hardy’s working interest fraction of the

gross resources. They do not represent Hardy’s actual net entitlement under the terms of the permits that govern these assets.

2. The primary Contingent Resource volume reported here is the 2C, or ‘Best Estimate’, value. 3. In the event of a commercial development of a discovery, ONGC has the option to back-into the CY-OS/2 licence at

an interest of 30%.

TABLE 0.6

SUMMARY OF GROSS AND NET GAS CONDENSATE CONTINGENT RESOURCES AS AT 31st DECEMBER, 2010


MMBbl Hardy

Interest (%)

Net Hardy Contingent Resources MMBbl

1C 2C 3C 1C 2C 3C GS-01- B1area 1.12 1.85 2.97 10 0.11 0.19 0.29 Total GS-01 1.12 1.85 2.97 10 0.11 0.19 0.29

Notes: 1. The Net Hardy Contingent Resources on this table are only indications of Hardy’s working interest fraction of the

gross resources. They do not represent Hardy’s actual net entitlement under the terms of the permits that govern these assets, which may be less.

2. The primary Contingent Resource volume reported here is the 2C, or ‘Best Estimate’, value.

Hardy 9 EE024430


TABLE 0.7 (Page 1 of 3)

SUMMARY OF GROSS AND NET GAS PROSPECTIVE RESOURCES FOR PROSPECTS


Licence Prospect

Gross Prospective Resources

Hardy Interest

(%)

Net Hardy Prospective Resources

GCoS (%)

BCF BCF

Low Estimate

Best Estimate

High Estimate

Low Estimate

Best Estimate

High Estimate

GS-01 B1 /

Deeper Miocene

34.0 68.0 126.0 10 3.4 6.8 12.6 30

GS-01 B1 /

Oligocene 95.0 160.0 259.0 10 9.5 16.0 25.9 20

GS-01 A1 198.0 335.0 558.0 10 19.8 33.5 55.8 25

GS-01 Prn1 /

Oligocene 9.0 19.8 53.2 10 0.9 2.0 5.3 10

GS-01 Prn1 / Eocene

13.0 34.2 84.0 10 1.3 3.4 8.4 10

CY-OS/2 Gap-A / Middle

110.0 173.0 251.0 75 82.5 129.8 188.3 15

CY-OS/2 Gap-A / Deep

93.0 130.0 179.0 75 69.8 97.5 134.3 15

CY-OS/2 Gap-B / Middle

70.0 111.0 164.0 75 52.5 83.3 123.0 15

CY-OS/2 Gap-B / Deep

65.0 122.0 188.0 75 48.8 91.5 141.0 20

CY-OS/2 Gap-E / Middle

61.0 91.0 128.0 75 45.8 68.3 96.0 15

CY-OS/2 Gap-B (N) /

Middle 32.0 47.0 67.0 75 24.0 35.3 50.3 10

CY-OS/2 Gap-B (NE)

/ Middle 28.0 45.0 67.0 75 21.0 33.8 50.3 10

CY-OS/2 Gap-F / Deep

40.0 65.0 103.0 75 30.0 48.8 77.3 5

D3

B1 Pleistocene

Sand 2 (Central)

30.0 127.0 330.0 10 3.0 12.7 33.0 80

D3

B1 Pleistocene

Sand 2 (Northern)

73.0 255.0 614.0 10 7.3 25.5 61.4 80

D3 F1

Pleistocene 88.0 272.0 589.0 10 8.8 27.2 58.9 80

D3 G1

Pleistocene 206.0 297.0 400.0 10 20.6 29.7 40.0 80

D3 K1

Pleistocene 123.0 410.0 879.0 10 12.3 41.0 87.9 80

D3 P1

Pleistocene 83.0 300.0 691.0 10 8.3 30.0 69.1 80

D3 D1

Pliocene 21.0 39.0 62.0 10 2.1 3.9 6.2 70

D3 E1 Pliocene 75.0 169.0 319.0 10 7.5 16.9 31.9 70

D3 L1 Pliocene 53.0 134.0 262.0 10 5.3 13.4 26.2 70

Hardy 10 EE024430





Licence Prospect


Hardy Interest

(%)


GCoS (%)

BCF BCF

Low Estimate

Best Estimate

High Estimate

Low Estimate

Best Estimate

High Estimate

D3 U1 Sand 1 Pliocene

52.0 134.0 291.0 10 5.2 13.4 29.1 70

D3 U1 Sand 2 Pliocene

74.0 161.0 306.0 10 7.4 16.1 30.6 70

D3 QA1 Sand 1 Pliocene 98.0 168.0 270.0 10 9.8 16.8 27.0 70

D3 U2 Sand Pliocene

72.0 166.0 318.0 10 7.2 16.6 31.8 70

D3 S1 Sand 1 Pliocene

39.0 68.0 104.0 10 3.9 6.8 10.4 70

D3 S1 Sand2 Pliocene

50.0 70.0 100.0 10 5.0 7.0 10.0 70

D3 T1

Pliocene 52.0 75.0 105.0 10 5.2 7.5 10.5 70

D3 G1

Miocene 112.0 328.0 675.0 10 11.2 32.8 67.5 70

D3 J1

Miocene 135.0 281.0 524.0 10 13.5 28.1 52.4 70

D3 M1

Miocene 175.0 464.0 904.0 10 17.5 46.4 90.4 70

D3 MM1

Miocene 191.0 388.0 645.0 10 19.1 38.8 64.5 70

D3 QA1 Sand 2 Miocene

204.0 308.0 455.0 10 20.4 30.8 45.5 70

D3 R1 Sand Miocene

23.0 38.0 58.0 10 2.3 3.8 5.8 70

D3 W1 Sand 3 Miocene

117.0 190.0 282.0 10 11.7 19.0 28.2 70

D3 H1

Oligocene 334.0 840.0 1,641.0 10 33.4 84.0 164.1 24

D3 Z1

Oligocene 89.0 300.0 703.0 10 8.9 30.0 70.3 24

D9

Channel Complex

C1 Pliocene

210.0 630.0 1,540.0 10 21.0 63.0 154.0 25

D9

Northern Anticline

(NW Flank B1) /

U. Miocene

800.0 2,500.0 5,600.0 10 80.0 250.0 560.0 20

Hardy 11 EE024430





Licence Prospect


Hardy Interest

(%)


GCoS (%)

BCF BCF

Low Estimate

Best Estimate

High Estimate

Low Estimate

Best Estimate

High Estimate

D9

Central Anticline

(NW Flank) / U. Miocene

400.0 1,100.0 2,100.0 10 40.0 110.0 210.0 20

D9

Central Anticline

(near B3) / U.

Miocene

1,000.0 2,500.0 5,300.0 10 100.0 250.0 530.0 20

D9

Southern Anticline (SE Flank C1) / U. Miocene

1,100.0 2,900.0 6,200.0 10 110.0 290.0 620.0 10

D9

Northern Anticline B1 / M. Miocene

1,300.0 2,500.0 4,500.0 10 130.0 250.0 450.0 20

D9

Central Anticline

(near B2) / M.

Miocene

1,300.0 1,900.0 2,700.0 10 130.0 190.0 270.0 20

D9

Southern Anticline C1/ M.

Miocene

1,300.0 1,900.0 2,600.0 10 130.0 190.0 260.0 15

D9

Northern Anticline (Near B1)

/ L. Miocene

1,800.0 6,300.0 15,000.0 10 180.0 630.0 1500.0 15

D9

Central Anticline

(near B2) / L.

Miocene

1,300.0 2,800.0 5,500.0 10 130.0 280.0 550.0 19

D9

Central Anticline (near A2)

/ L. Miocene

800.0 2,300.0 4,900.0 10 80.0 230.0 490.0 15

Notes: 1. The Geologic Chance of Success (GCoS) reported here represents an indicative estimate of the

probability that the drilling of this prospect would result in a discovery which would warrant the re-categorisation of that volume as a Contingent Resource. The GCoS value for Contingent Resource is 100%. These GCoS percentage values have not been arithmetically applied within this assessment.

2. It is inappropriate to sum Prospective Resource volumes or to otherwise focus upon those of other than the ‘Best Estimate’.

3. In the event of a commercial development of a discovery, ONGC has the option to back-into the CY-OS/2 licence at an interest of 30%.

Hardy 12 EE024430


TABLE 0.8

SUMMARY OF GROSS AND NET OIL PROSPECTIVE RESOURCES FOR PROSPECTS AS AT 31st DECEMBER, 2010




Licence Prospect


Hardy W.I. (%)


GCoS (%)

MMBbl MMBbl

Low Estimate

Best Estimate

High Estimate

Low Estimate

Best Estimate

High Estimate

D9

Central Anticline (4 way fault

closure B2) / Palaeocene

142.0 420.0 961.0 10 14.2 42.0 96.1 18

D9

Central Anticline

(Fault Closure B2) / Cretaceous

44.0 122.0 260.0 10 4.4 12.2 26.0 18

Hardy 13 EE024430


1. DISCUSSION

Hardy has five assets offshore India as shown in Figure 0.1. In the Bay of Bengal, beyond the Krishna-Godavari Basin, are the deepwater exploration Blocks KG-DWN-2003/1 (or KG D3) (NELP V) and KG-DWN-2001/1(or KG D9) (NELP III), while further south, in the Cauvery Basin is the production license PY-3 and the exploration licence CY-OS/2, (which surrounds the producing field PY-1). In the Arabian Sea, lies licence GS-OSN-2000/1 (NELP II in the Bombay Basin). Additionally, Hardy is a partner in the onshore Assam Block (AS-ONN-2000/1) exploration licence within the Assam-Arakan Basin, North-East India. 1.1 Cauvery Basin The Cauvery Basin is located half onshore and half offshore Tamil Nadu, South-East India. It is the most southerly basin on the east coast and encloses an area of more than 50,000 km2. It was formed during Late Jurassic/Early Cretaceous rifting as a result of the break-up of eastern Gondwanaland. The NE-SW-orientated sub-basins characterising the Cauvery Basin are an en-echelon array of horst and graben structures formed during this rifting and dominated the structural grain of the basin, following which they subsided as part of a passive margin. The dominant structure was formed by a north/south dextral strike-slip movement between the main Indian sub-continent and Sri Lanka. In the Hardy acreage lie the Ariyalur-Pondicherry and Tranquebar sub-basins are separated by the Porto Novo High (on which lies the PY-1 gas field) as shown in Figure 1.1. The basement is Precambrian (Archean), overlain by sediment fill, which in places reaches a thickness of 7,000 m and ranges in age from Permo-Carboniferous to Recent. Earliest syn-rift deposition during the Barremian-Aptian led to fluvio-lacustrine deposits in half-grabens followed in the early Albian by a marine transgression. The main extensional phase occurred in the mid-Albian, with associated footwall uplift and erosion. Eroded material from the basin edges was trapped in adjacent lows as fault-scarp conglomerates, and transported further as turbidite sand bodies. These turbidites, where embedded in organic marine shales, constitute a viable petroleum exploration play. Rifting ceased in the Cenomanian or Turonian after which thermal subsidence predominated. The post-rift stratigraphy consists of unconformable packages of mainly shallow marine and fluvial sandstones and sand-rich carbonates (see the lithostratigraphic column Figure 1.2). The source rocks in the basin are organic-rich marine black shales of the Karai Clay Formation deposited in Albian/Aptian to Turonian times. These organic shales can be 100 m thick. They are overlain by major reservoir sand bodies such as the Bhuvanagiri, Nannilam (the reservoir in the PY-3 Field), and Kamalapuram ranging in age from Cenomanian to Eocene (Figure 1.2). The reservoir units are sealed by shales and limestones in a cyclic sequence. Exploration targets have progressed from the structural graben-horst features, to deepwater sands and stratigraphic traps such as those drilled by Hardy in wells Fan E-1 and Fan A-1 (subsequently known as Ganesha-1) in 2006. Proven traps in the Cauvery basin include structural and combination traps and pure stratigraphic traps such as pinchouts and isolated sands. Proven reservoirs include fractured basement (PY-1 Field) and Cretaceous (syn-rift) sands and Miocene sands. 1.1.1 PY-3 Field (Hardy NWI 18%)

The PY-3 Field is located in the Cauvery offshore basin. It commenced production in July, 1997, and is presently the only producing oil field in Production Licence CY-OS-90/1 (Figure 1.1). The Licence covers some 81 km2 and the water depth ranges from 40 m to about 450 m. The field is operated by Hardy, which holds an 18% Net Working Interest under a Production Sharing Contract (PSC) with The Government of India. The other licensees are ONGC (40%), Tata

Hardy 14 EE024430


Petrodyne (21%) and HOEC (21%). The PSC expires in December, 2019, but can be extended by mutual agreement for a further five years. Hardy has made available to GCA a dataset of technical information that included the Hardy geological model (in Petrel) and seismic data, velocity cube, petrophysical summary, ECLIPSE model, artificial lift selection study, well test analysis plus all available production and injection data together with financial data, including the PSC and cost data. Production data have been used to update the reserves since the 2010 CPR. No further geological work since the 2010 CPR has been presented.

Geology & Geophysics

The PY-3 Field is sited within the Tranquebar sub-basin some 25 km south of the PY-1 Field. Reservoir sands are present in the Coniacian-Maastrichtian Nannilam Formation, which is the main prospective reservoir across both PY-3 Field and Block CY-OS/2. These reservoirs are debris flows (i.e. turbidites) that are poorly sorted, deposited in lows and have a fan/lobe-like morphology. They vary in thickness, and are laterally and vertically discontinuous. There are numerous unconformities and pinchouts throughout the geologic section. The entire geological sequence appears to be located on the old and present day slope edge. A significant lateral velocity gradient across the field makes depth conversion complex, compounded by the rapidly-changing water bottom.

Hardy defined 5 reservoir units in PY-3 Field, with the upper two zones being on production. There were six horizons mapped in two-way-time on basic 2D or 3D seismic data. Some faults, observed on the seismic, were not mapped. Hardy's current interpretation of the top reservoir is given in Figure 1.3 which shows the locations of existing and proposed development wells.

Hardy 15 EE024430


FIGURE 1.1

LOCATION OF PY-3 FIELD AND BLOCK CY-OS/2, OFFSHORE CAUVERY BASIN, INDIA

CY-DWN2001/2CY-DWN2001/2CY-DWN2001/2CY-DWN2001/2CY-DWN2001/2CY-DWN2001/2CY-DWN2001/2CY-DWN2001/2CY-DWN2001/2

BHUVANAGI.02BHUVANAGI.02BHUVANAGI.02BHUVANAGI.02BHUVANAGI.02BHUVANAGI.02BHUVANAGI.02BHUVANAGI.02BHUVANAGI.02

CY-ONN2002/1CY-ONN2002/1CY-ONN2002/1CY-ONN2002/1CY-ONN2002/1CY-ONN2002/1CY-ONN2002/1CY-ONN2002/1CY-ONN2002/1



CY-ONN2004/2CY-ONN2004/2CY-ONN2004/2CY-ONN2004/2CY-ONN2004/2CY-ONN2004/2CY-ONN2004/2CY-ONN2004/2CY-ONN2004/2 KALIKALIKALIKALIKALIKALIKALIKALIKALI

KUTHALAMKUTHALAMKUTHALAMKUTHALAMKUTHALAMKUTHALAMKUTHALAMKUTHALAMKUTHALAM

L-IL-IL-IL-IL-IL-IL-IL-IL-I

L-I (EXTN.)L-I (EXTN.)L-I (EXTN.)L-I (EXTN.)L-I (EXTN.)L-I (EXTN.)L-I (EXTN.)L-I (EXTN.)L-I (EXTN.)

L-XIL-XIL-XIL-XIL-XIL-XIL-XIL-XIL-XI

MADANAM

MYILADUTHURAI

NEYVELI

Sri Lanka

nnnnnnnnn


NepalPakistanPakistanPakistanPakistanPakistanPakistanPakistanPakistanPakistan



Bhutan

Myanmar



0 30 Km

CY-OS-2

PY-3 Field

Ganesha-1 Well


Oil Field

LEGEND

Gas FieldGas Condensate Field

Karaikal High

MadanamHigh

Porto NovoHigh

Indian Craton

T r a n q u e b a r S u b b a s I n

High Areas


CY-OS-90/1

PY-1 Field

Fan E-1 Well

CY-OS-2

Porto NovoHigh

Hardy 16 EE024430


FIGURE 1.2

CAUVERY BASIN LITHOSTRATIGRAPHIC COLUMN

Age LithostratigraphyRegional / BasinalTectonic Events U

nit Play /

Play Fairways

Res

ervo

ir

So

urc

e

Sea

l

Post Mid-Miocene

Eocene to Mid-Miocene

Paleocene to Eocene

Coniacian to Maastrichtian

Uni

t 6U

nit 5

Uni

t 4U

nit 3

Uni

t 2U

nit 1

Bas

emen

t

Albian/Cenomanian/

Turonian

Pre-Albian

Pre-Cambrian

Rif ting of EastGondwanaland

Madagascarseparated f rom

India/Reactivationof Basement Highs

S Y

N R

I F

TP

O

S

T

-R

I

F

T

Deccan trapvolcanism/basin tilt SE

Indian platecollided withTibetan plate

Indian platecollided with

Eurasian plate/basin tilt E

Niravi Play

Kamalapuram

Nannilam(PY-3 Reservoir)

Bhuvanagiri

Syn Rif t

FracturedBasement

(PY-1 Reservoir)

UNCONFORMITY

UNCONFORMITY

UNCONFORMITY

UNCONFORMITY

UNCONFORMITY

UNCONFORMITY

+

Source: Hardy

Hardy 17 EE024430


FIGURE 1.3

PY-3 PAY TOP STRUCTURE MAP WITH OWC @3,505 m SS

Following Hardy’s 2006 3D interpretation, additional volumes were attributed to the field in the South-East, North-East and core area. The core area comprises the main producing area, which had increased in volume as a result of raising the structure and incorporating two deeper reservoir zones within closure. The seismic, wells, velocity field and top and base of the PY-3 reservoir were validated. It is GCA's opinion that there exists some uncertainty under and around the rapid water-bottom change in the North-East. Several seismic, velocity and depth profiles showed that there is a significant velocity gradient laterally from shallow to deep water within the two-way time interval of about 1,200 ms to 3,300 ms, which clearly impacts on the conversion to the depth structure map. Ongoing work is currently revising the interpretation in the North-East area. It is GCA's opinion that there still remains uncertainty in the presence of debris flows in the west and South West and questionable structural closure to the North East. However, Hardy’s recent work through field re-mapping, revised geological modelling and additional petrophysical analysis has increased the level of confidence in Hardy’s volumetric estimations. STOIIP values reported by Hardy in November, 2009 were 132.5 137.5 and 152.5 MMBbl considering core area, core- South-East, and core- South-East, North-East respectively (Figure 1.4). GCA accepted Hardy’s STOIIP figures.

Hardy 18 EE024430


Production Performance

The PY-3 Field has been producing since July, 1997. Production wells are subsea tied back to a floating production facility and oil is exported by shuttle tanker. The facility at PY-3 consists of the floating production unit, ‘Tahara’, and a 65,000 DWT tanker, ‘Endeavor’, which acts as a floating storage and offloading unit. Liquid processing capacity on Tahara is 20,000 stbd with 17 MMscfd of gas handling capacity. The field currently produces associated gas in the range of 3.5 MMscfd. This produced gas is used as fuel gas with excess gas being flared. The extension of the Tahara contract for 18 months from 24th January, 2011 to 23rd July, 2012 is currently being negotiated. GCA review of wells and field performance up to end of December, 2010 indicated a cumulative production of 24.1 MMBbl. After its start, PY3 production peaked to around 10,000 bopd in 1998, and declined gradually afterward mainly because of water breakthrough and eventually the shutdown of wells. Currently, the field is producing from well PD3S at around 3,400 bopd, with water injection into the reservoir via wells 3-2RST-RL and 3-3-3RL at around 5,700 bwpd. GOR is around 1,170 scf/Bbl, about 0.5% water cut and 3,746 psi (PDHG) reservoir pressure.

FIGURE 1.4

PY-3 PAY TOP STRUCTURE MAP_VOLUMETRIC POLYGONS

Northeast

Southeast

Core + NE + SE

Core

Hardy 19 EE024430


Until July 2008, water injection was insufficient (from one injector) to maintain reservoir withdrawals and the wells were often choked back to control GOR. At present, Hardy is injecting at around double voidage replacement which is supporting an increased oil rate and at the same time keeps GOR at a practical level.

Dynamic Reservoir Modelling

Hardy’s history match process up to 2009 has only been applied to the oil production and GOR (beside few static reservoir pressure points) because there have been no flowing bottomhole pressure data in the field since 2004 and no significant water production. Hardy, however, has recently updated its simulation model by including history match to BHP, THP and adding lift curves, which was added more confidence to the dynamic model. However, GCA considers that the water production data collected to date are still insufficient to allow the establishment of a reliable water cut history match. Hardy continues to analyse the water production to determine the scenario that best represents PY-3’s water cut performance. In its audit of Hardy’s dynamic model, GCA found that the Hardy’s history match for oil rate, GOR and the pressure data is reasonable and considers it suitable for forecasting purposes.

Production Forecast

Hardy’s Phase III development of the PY-3 Field envisages the drilling of two further wells. Hardy’s approach to the estimates of remaining recoverable oil is based on the following two cases:

Case 1: Do nothing; and Case 2: Phase III, 2 new producers and the activation of well PD-4RL. Hardy’s simulation results support the implementation of the Phase III development plan and should lead to a significant increase in the volume of oil produced, and thereby enhance oil recovery (Figure 1.5).

Hardy 20 EE024430


FIGURE 1.5

PY-3 FIELD PRODUCTION PERFORMANCE AND FORECAST

Oil Reserves

Proved Reserves This is based on field historical performance and assumes a do nothing case where oil production is allowed to decline from its current rates. The Gross Proved Reserves as at 31st December, 2010 are estimated at 2.51 MMBbl (0.38 MMBbl Net Entitlement to Hardy). Proved plus Probable Reserves

For the Proved plus Probable Reserves case, GCA incorporated Hardy’s Phase III field development plan by including two further producers to be drilled in January, 2012 and the activation of well PD-4RL. The resulting estimated Gross Proved plus Probable Reserves as at 31st December, 2010 are 15.07 MMBbl (2. 1 MMBbl Net Entitlement to Hardy). Proved plus Probable plus Possible Reserves

This is based on PY-3 Field performance, Hardy’s Phase III activities, and three further producers in the north, North-East & South-East parts of the Field that are to come on stream in July, 2013. GCA estimated Gross Proved plus Probable plus Possible Reserves are at 21.39 MMBbl (2.9 MMBbl Net Entitlement to Hardy as at 31st December, 2010). Figure 1.5 summarises Hardy’s three forecast cases.

0

50

100

150

200

250

300

350

400

450

500

Mo

nth

ly O

il (M

Bb

l)

History 1P 2P 3P

Hardy 21 EE024430


1.1.2 Block CY-OS/2 (Hardy NWI 75%, Operator)

The CY-OS/2 Block is located in the Cauvery Basin and encompasses an area of 859 km2. The CY-OS/2 Block, which after various relinquishments is now split into northern and southern sectors, (Figure 1.1), is operated by Hardy. Hardy has a 75% WI, and remaining 25% is held by GAIL. Water depths over the retained areas range from a few tens of metres at points where the acreage is 2 km from the shore, to almost 500 m at its remotest point (Figure 1.1).

The Block was awarded in 1996 under a PSC, the terms of which provided for three exploration phases, the last of which expired, with all commitments fulfilled, on 23rd March, 2007. The PSC provides for 100% Cost Recovery and Profit Oil sharing. As the PSC pre-dates the NELP, in the event of a commercial discovery, ONGC has the option to back-into the block at an interest of 30%. At the time of this report, a proposed appraisal programme (approved by the operating committee) is being reviewed by the Directorate General of Hydrocarbons (DGH). Hardy is involved in a debate on the nature of fluid in well Fan-A-I (aka Ganesha-1) discovery with the DGH. Hardy maintains the discovery as gas based on the test results and the results of DST-2 where it flowed around 10.7 MMscfd of gas with some condensate. DST-1 was inconclusive because the tubing became plugged while testing and the well flowed small quantity of fluids but was predominantly gas with condensate. The DGH has restricted the appraisal period to 24 months from discovery date interpreting the discovery as oil. Hardy has submitted all the relevant documents to the MOPNG and the DGH supporting the nature of the discovery as gas. The documents provided to the DGH, included the DST reports by Schlumberger, the CPCL (Chennai Petroleum Corporation Limited) laboratory reports on the liquid samples collected from DST#1 & #2 and the ISM University report. Hardy has submitted to the DGH the legal opinions from an independent lawyer and from the Attorney General of India, which opines that Hardy should get 60 months extension under the PSC. The significance of this is that if it is only oil, then there is a twenty four month appraisal period from January, 2007; if it is oil and gas where gas predominates, then there is a five year appraisal period from January, 2007. In accordance with the dispute resolution provisions of the PSC, Hardy and the GOI have appointed arbitrators to resolve the dispute described above. As of this date each party has made initial filing and the arbitration process is ongoing. In the preparation of this CPR, GCA has accepted Hardy’s explanation but acknowledges that the decision of the MOPNG, GOI could have a significant impact on the CY-OS/2 license. The CY-OS/2 Block contains 12,000 line km of 2D seismic, 1,381 km of which have been re-processed. Four 3D seismic surveys have been shot totalling almost 830 km2.

Two relinquishments have been made, one at the end of each of the first two exploration phases. In the final exploration phase, from May, 2005 to March, 2007, Hardy has acquired 653 km2 of the above 3D (617 km on-block) and drilled two wells; Fan E-1, which was dry (the main Eocene reservoir was absent), and Fan A-1, as described earlier. This well is now renamed Ganesha-1. Well Fan E-1 is in the Tranquebar sub-basin, and well Ganesha-1 is in the Araiyalur-Pondicherry sub-basin to the north (Figure 1.1). No additional geoscience work since the 2010 CPR has been presented. Work is in abeyance while dispute resolution process is ongoing.

Well Fan A-1 (Ganesha-1)

The Ganesha-1 well was spudded on 26th September, 2006, and was drilled as a vertical hole to a depth of 4,089 m MD where it terminated in Turonian Sattapadi shales, having intersected all planned targets. Hydrocarbon shows were logged in the Nannilam (Campanian) and Bhuvanagiri (Turonian) Formations, and between these a thin sand flow-tested gas.

Hardy 22 EE024430


The prospective intervals were seismically identified fans that relied upon updip pinchout of the re-worked shelfal sands against shale-prone deepwater slope sediments. Top seal was provided by transgressive deepwater shale. The dual nature of the potential targets – Campanian sands of the Nannilam Formation underlain by Turonian sands of the Bhuvangiri Formation – is seen very clearly, partly because of anomalous seismic amplitude response, particularly at the shallower level.

The well found several sands of various ages: Campanian sands (Top Fan), Santonian - Coniacian thin sand intervals within the Kudavasal Shale Formation (Middle Fan sand) and Turonian (Deep Fan sand). Shows were observed in the cuttings while drilling through each sand. Flow tests were run on the Deep Fan sand and the Middle Fan sand. According to the Final Geological Report for the well, the Top Fan sand, in which 50 m of net sand were intersected, was not tested because of heavy mud losses experienced while drilling. Two MDT samples in this sand provided no representative formation fluid (though they revealed the presence of gas). Hydrocarbon shows were encountered during drilling, at three (possibly four) zones in the Top Fan sand.

The Deep Fan sand, (3,759 m MD) comprises two sand bodies each about 20 m thick separated by 15 m of shale. Net sand was about 35 m, with log-derived porosity 14-17%. The zone from 3,800 - 3,809 m was tested, producing a weak flow of gas and condensate, and anomalously ‘fresh’ water (all test results are summarised below). DST-1, in the Deep Fan sand, is considered unreliable due to the reported heavy mud losses. This may have been contributed to poor casing cementation, so the well was sidetracked a horizontal distance of about 250 m at the target level. This time the Bhuvanagiri sandstone occurred as a single 45 m sand. Two tests were run, opening perforations from 3,775-3,795 m (DST-4), and then 3,779-3,785 m plus 3,805-3,812 m (DST-4A). The results essentially replicated those of DST-1; as before, the cement bond log indicated poor cementation. Table 1.1 is a summary of Ganesha-1 DST results.

TABLE 1.1

WELL GANESHA-1: SUMMARY OF DST RESULTS

Interval Test Depth (m MD)

Results

Deep Fan Sand DST-1 3,800 – 3,809 Max gas 0.47 MMscfd, Max cond. 2.4 bcpd,

Freshwater c. 120 bpd

Middle Fan Sand DST-2 3,565 – 3,569 Max gas 10.7 MMscfd, Max gas 10.7 MMscfd falling to 1.47 MMscfd

Middle Fan Sand DST-3 3,336 – 3,341 Intermittent gas 0.1 MMscfd Deep Fan Sand DST-4 (in ST) 3,775 – 3,795 100 bpd freshwater with weak gas flow

Deep Fan Sand DST-4A (in ST) 3,779 – 3,785 & 3,805 – 3,812

Gas flow 0.47 MMscfd plus freshwater

The water produced in DST’s 1, 4 and 4A was typically of salinity 2,500 – 2,800 mg/litre. GCA’s petrophysical analysis has shown that this does not correspond to the formation water. The Middle Fan sand was encountered between 3,565 - 3,569 m. The zone flowed gas (DST-2) at rates which declined from a maximum of 10.7 MMscfd to 1.47 MMscfd showing that a small permeable reservoir was tested and depleted on production. The reservoir had a channel-like morphology: long (119 m) and narrow (37 to 58 m) and thin (1 m). This tight reservoir may recharge from surrounding low permeable sandstones but the stable flow rate would be less than 1.14 MMscfd based on a reservoir engineering study. A further 5 m section, at 3,336 - 3,341 m was tested by DST-3, but also yielded disappointing results. GCA agrees with Hardy’s interpretation of hydrocarbon presence in both the Deep Fan sand and in the Middle Fan sand. GCA also supports Hardy’s gas case based upon well test results. GCA’s

Hardy 23 EE024430


analysis confirms 217 BCF as Best Estimate GIIP figure for the accumulation. GCA’s estimated Contingent Resources for the Ganesha-1 discovery is shown in Table 1.2 below

TABLE 1.2

SUMMARY OF CY-OS/2 GROSS AND NET GAS CONTINGENT RESOURCES


Gross Contingent Resources BCF

Hardy Interest

(%)

Net Hardy Contingent Resources BCF

1C 2C 3C 1C 2C 3C

CY-OS/2- Ganesha-1 69.1 130.0 222.5 75 51.8 97.5 166.9 Total CY-OS/2 69.1 130.0 222.5 75 51.8 97.5 166.9 Notes: 1. The Net Hardy Contingent Resources on this table are only indications of Hardy’s working interest fraction of the


2. The primary Contingent Resource volume reported here is the 2C, or ‘Best Estimate’, value. 3. In the event of a commercial development of a discovery, ONGC has the option to back-into the CY-OS/2 licence at

an interest of 30%. Ganesha-1 area Prospects

Since GCA’s CPR of 2010 the resources remain unchanged. A study was conducted by Hardy using the reprocessed 3D seismic data (AVO/AVA and derivative products) to mitigate the risk of drilling the Fan-A/Ganesha appraisal well; and to define the vertical and lateral limits of the Fan-A-1 Deep and Middle hydrocarbon-bearing sands. Several seismic attribute volumes were generated including P-Impedance, S-Impedance, Vp/Vs, density LamdaRho, MuRho, and Poissons’s Ratio. Proprietary software provided by CGG generated geobodies from the 3D inverted seismic data using the seismic data. In this instance, the Lamda-Rho versus Vp/Vs was used to extract the geobodies using different cut-offs for the P90, P50 and P10 cases. These data were merged with a spectral decomposition (seismic frequency analysis for thin beds) data to identify prospective areas for appraisal drilling. The northern area is called Ganesha Appraisal-A (Gap-A) and Gap-A-1, both about 2 km from the discovery well. The southern area is called Gap-B , and lies about 14 km from the discovery well. The spectral decomposition was convincing in the southern, Gap B area. These and the other seismic data are supporting evidence, but are not themselves conclusive.

Extraction of geobodies from AVO/AVA volumes represents state-of-the-art technology application in geophysics but caution is required when interpreting what these ‘geobodies’ represent. It is well known that because of the link to seismic amplitudes, false positives are common with geobody extractions. This method of extraction assumes that the seismic amplitude is related to hydrocarbon effects only; whereas, the seismic wavelet is constructed from changes in lithology (vertical and horizontal), stratigraphy (thick, thin, tuning, unconformities, etc.) and fluid content (oil, gas, water). Often, geobodies are extracted for reasons that are non-hydrocarbon related; and, are sensitive to cut-offs. Additionally, the extracted geobodies are discontinuous and fragmented which suggests lateral changes in lithology, stratigraphy and fluid content. GCA performed an independent volume estimate based on the data supplied by Hardy. The relationship between seismic attribute analysis and presence of hydrocarbons is ambiguous and inconclusive. Consequently, it was used as a guideline for the GCA area estimates. Gross/Net thickness, porosity and water saturation were obtained from logs where available. Thickness

Hardy 24 EE024430


estimates used by GCA to compute volumetrics are lower than those used by Hardy to reflect the broken distribution of the strong attributes and indeed areas of no seismic response, the lack of supporting evidence for fluid trapping mechanism within potential reservoir imaged, and the limited confidence that can be placed on the calibration via a single control point. It should be noted that in the various Ganesha area probabilistic cases, the extracted geobodies did not always intersect the discovery well so extrapolating lithology and fluid content is risky. It should also be mentioned that not all the geobodies seemed geological in form, or were associated with an obvious structural trap. The amplitude derived geobodies in some cases parallel structural contours in a way more usual with tuning, than with stratigraphic or structural traps. Therefore GCA has lowered the GCoS for these Prospects compared to the GCoS originally proposed by Hardy.

Prospective Resources can be attributed to Block CY-OS/2 based on the results of Fan-A-1 well and geobody analysis discussed above (Figure 1.6). These are considered as Prospects. There are 4 locations, Gap-A, Gap-B, Gap-E and Gap-F that are related to appraising the Ganesha discovery. GCA audited Hardy’s volume estimates for these Prospects and made changes where appropriate. GCA’s current GIIP estimates are as listed in Table 1.3 below.

TABLE 1.3

GANESHA-1: SUMMARY PROSPECTS GROSS

GIIP (BCF)

Prospect Horizon GIIP

Low Estimate Best Estimate High Estimate

Gap-A Middle Sand 183 288 418 Gap-A Deep Sand 155 217 298 Gap-B Middle Sand 116 185 273 Gap-B Deep Sand 115 209 320 Gap-E Middle Sand 102 152 214 Gap-B (N) Middle Sand 53 79 111 Gap-B (NE) Middle Sand 47 75 111 Gap-F Deep Sand 67 109 171 Note: 1. It is inappropriate to focus on any of these volume postulations other than the ‘Best Estimate’.

Hardy 25 EE024430


FIGURE 1.6

CY-OS/2 PROSPECT LOCATION MAP

Deep Fan

Middle Fan

Source: Hardy

Hardy 26 EE024430


GCA’s estimated Prospective Resources for these Middle and Deep Fan sands are shown in Table 1.4 below.

TABLE 1.4



Licence Prospect


Hardy W.I. (%)


GCoS (%)

BCF BCF

Low Estimate

Best Estimate

High Estimate

Low Estimate

Best Estimate

High Estimate

CY-OS/2 Gap-A / Middle

110.0 173.0 251.0 75 82.5 129.8 188.3 15

CY-OS/2 Gap-A / Deep

93.0 130.0 179.0 75 69.8 97.5 134.3 15

CY-OS/2 Gap-B / Middle

70.0 111.0 164.0 75 52.5 83.3 123.0 15

CY-OS/2 Gap-B / Deep

65.0 122.0 188.0 75 48.8 91.5 141.0 20

CY-OS/2 Gap-E / Middle

61.0 91.0 128.0 75 45.8 68.3 96.0 15

CY-OS/2 Gap-B (N) /

Middle 32.0 47.0 67.0 75 24.0 35.3 50.3 10

CY-OS/2 Gap-B (NE)

/ Middle 28.0 45.0 67.0 75 21.0 33.8 50.3 10

CY-OS/2 Gap-F / Deep

40.0 65.0 103.0 75 30.0 48.8 77.3 5




3. In the event of a commercial development of a discovery, ONGC has the option to back-into the CY-OS/2 licence at an interest of 30%.

1.2 Saurashtra Basin (west of Mumbai Offshore Basin) The Mumbai Offshore Basin extends over 145,000 km2. It is bounded to the east by volcanic lava flows known as the Deccan Trap and to the south by the E-W-trending Pre-Cambrian Panjim Ridge. Adjacent basins are the Saurashtra Basin to the north and the Cambray Basin to the North East. Block GS-01, in which Hardy has a 10% working interest, lies 220 km west of Bombay and 60 km south of the Saurashtra Peninsular straddling the Bombay and Saurashtra basins. The Mumbai Basin is characterised by NNW-SSE horst and graben systems, developed during the Palaeogene. The most prominent horst is the Mumbai High (Figure 1.7). The Mumbai High oil field was the first discovery in the basin, made in 1974, in Miocene carbonates. Since then the basin has experienced continuous exploration, which has resulted in the discovery of many other oilfields, including Ratna, Heera, Panna, Mukta, and Neelam, and the gas fields of Bassein, South Bassein, Mid Tapti and South Tapti.

Hardy 27 EE024430


FIGURE 1.7

GS-01 BLOCK LOCATION

Onshore geology is principally basalt lavas overlying crystalline basement. In deeper areas Upper Cretaceous sediments can be preserved beneath the Deccan Trap. The basalts are overlain by continental and estuarine clastic sediments of the Upper Palaeocene to Lower Eocene (Panna) formations (Figure 1.8). Offshore the thickness of basin fill can exceed 8,000 m. The majority of the 600 exploration

Sub-sea Oil Pipeline (Existing)

Oil FieldLEGEND

Sub-sea Gas Pipeline (Existing)

BOMBAY HIGH

C24

MID. TAPTI

S. TAPTI

PANNA

BASSEIN

HEERA

RATNA

Arabian Sea

DIU

MUKTA

UranTerminal

Mumbai

To Hazira

36" 42"

26"

26"

0 25 50 75 100 Km

30"

Gas Field

C23

Bombay Basin

Gujarat-SaurashtraBasin

Basin Limits

Sri Lanka

nnnnnnnnn





Bhutan

Myanmar



GS-01

BASSEIN S.


Original Area

Retained Area

Hardy 28 EE024430


and appraisal wells that have been drilled in the Basin have tested the section down to the Deccan Trap or Precambrian granitic basement. During Upper Eocene to Lower Oligocene thick carbonate successions were deposited. The Upper Oligocene to Middle Miocene succession of the Alibag, Bombay-Ratnagiri and Saurashtra formation is predominantly carbonate in the central and southern part of the basin but in the north and west it is fine clastic lithology. From Upper Eocene to Middle Miocene a shallow marine environment of deltas and lagoons was widespread. The Tarapur Fm (Middle Miocene to Recent) was deposited over the entire basin as thick regional shale.

FIGURE 1.8

OFFSHORE MUMBAI BASIN LITHOSTRATIGRAPHIC COLUMN

Miocene to Recent

Clay (soft,plastic), Shale

Predominantly claystone & silts

Secondary Target-I-Top of Reef 3Limestone with minor shale/marlstone

Primary Target - I-Lr. Miocene Limestone

Primary Target - II-Ur. Oligocene Limestone

Secondary Target-II- Bassein LimestoneLimestone with minor shale/marlstone

Secondary Target-III- Panna LimestoneLimestone with minor shale/marlstone

Mid

Miocene

Lower Miocene

Oligocene

Up. Cretaceous (?)

Mid Eocene

Trap wash: Weathered basalt & minor shale/siltstone

Volcanics:Basalt

Early Eocene

Late Paleocene

Miocene to Recent








Mid

Miocene

Lower Miocene

Oligocene

Up. Cretaceous (?)

Mid Eocene


Volcanics:Basalt

Early Eocene

Late Paleocene

Miocene to Recent








Mid

Miocene

Lower Miocene

Oligocene

Up. Cretaceous (?)

Mid Eocene


Volcanics:Basalt

Early Eocene

Late Paleocene

Miocene to Recent








Mid

Miocene

Lower Miocene

Oligocene

Up. Cretaceous (?)

Mid Eocene


Volcanics:Basalt

Early Eocene

Late Paleocene

Miocene to Recent








Mid

Miocene

Lower Miocene

Oligocene

Up. Cretaceous (?)

Mid Eocene


Volcanics:Basalt

Early Eocene

Late Paleocene

FORMATION LITHOLOGY AGE OBJECTIVES

Pre CambrianBasement

Deccan Trap

Panna

Bassein

Heera/Mahum

Alibag

Bombay-Ratnagiri

Saurashtra

Tarapur

Intrusives/Metamorphics

Claystone Limestone Sandstone Trapwash Volcanics Siltstone

Marlstone Shaly Limestone

Claystone Limestone Sandstone Trap wash Volcanics Siltstone






Claystone Limestone Sandstone Trap wash Volcanics Siltstone


Claystone


Limestone Sandstone Trapwash Volcanics Siltstone

Source: Hardy

Hardy 29 EE024430


Proven producing reservoirs are Lower and Middle Miocene lagoonal wackestones with secondary targets of Oligocene and mid Miocene limestone build-ups. The main source rocks are the Palaeogene and Miocene pro-delta muds deposited in intra-basinal lows. The main such ‘kitchen’ is the Dahanu Depression, extending for around 500 km parallel to and offshore from the present-day coastline. There is a second kitchen below GS-01, the Hardy block, where the source rocks below 3,500 m are over-mature and mainly gas-prone. There are no known carrier beds so, although close, migration between kitchen and reservoirs required either fault plane routes or reservoir-reservoir juxtaposition Migration began in early Miocene into Palaeogene reservoirs, and continued in a second phase into Lower and Middle Miocene reservoirs during the Pliocene, when traps were already formed. Typical trap types are rollover anticlines, fault-bounded monoclines and stratigraphic carbonate traps (including reefal structures) (Figure 1.19).

FIGURE 1.9

TRAP STYLES IN THE MUMBAI BASIN

Source: USGS

Hardy 30 EE024430


1.2.1 Block GS-01 (Hardy NWI 10%) Block GS-01 encompasses 8,841 km2, and lies in water depths varying from 50 m to 90 m. The block is operated under a PSC by RIL whose working interest is 90%. Hardy has the remaining 10%. The exploration concession (PEL) was awarded on 16th August, 2001 under NELP II terms, comprising: Three exploration phases, each not exceeding three years, for a total period of seven years; The operator has elected not to go to exploration Phase II but to go straight to the

development phase.

An extensive geophysical database exists over GS-01 including 2D and 3D seismic and potential field data. Prior to Hardy’s involvement in the licence, six exploration wells had been drilled in the northern half of the block. None of these wells encountered commercial hydrocarbons although B-107-1, drilled by ONGC in 1990, is reported to have oil shows. RIL and Hardy have drilled four wells: S1, M1, GS01-A-1 and GS-01-B-1. Figure 1.10 shows the locations of these four wells and the remaining Prospects. No additional geoscience work has been undertaken since the 2010 CPR as Hardy is in correspondence with the DGH pertaining to the declaration of commerciality of the Dhirubai-33 discovery submitted to the DGH on 28th August, 2010.

1.2.1.1 Contingent Resources

Dhirubhai 33 (GS-01-B1) Well GS-01-B1 was spudded on 2nd March, 2007, 240 km North West of Mumbai in 79 m of water and at 2,282 m MD (2,256 m TVDSS) reached TD in Lower Miocene reefal carbonates. The structure being tested was a narrow, four-way dip-closed anticline, as shown at Top Bassein (Eocene) level in Figure 1.11. The well had been planned to intersect several limestone targets, from Middle Miocene through to Lower Eocene (Panna Fm) but the well terminated prematurely in the Lower Miocene due to mud losses/lost circulation. It had encountered gas and condensate in Lower Miocene limestones before entering reefal material of high vuggy porosity and permeability. Twenty-four metres of perforations were opened within the Lower Miocene fractured dolomitic reservoir above the reef, and following acidisation the well flowed gas at 18.6 MMscfd and condensate at 415 bcpd through a 56/64” choke with a FTHP of 1,346 psi. Levels of hydrogen sulphide between 1,700 ppm and 3,800 ppm, and CO2 up to 7% were noted in the produced gas. GCA assumed a Condensate Gas Ratio (CGR) of 22.3 Bbl/MMscf based on GS-01-B1 test results. A test was attempted within the reef, but this failed, possibly because of earlier efforts to stem the mud losses with cement. The operator officially notified the government of a discovery named Dhirubai 33, on 14th May, 2007. It is the most westerly discovery in India to date. A Declaration of Commerciality was submitted to GOI in 2010. An estimate of Contingent Resources for the tested zone is presented in the Tables 1.5 and 1.6 below. Hardy’s 1C, 2C and 3C estimates of GIIP, 72, 111 and 167 BCF respectively, seem reasonable based on the data provided to GCA. Recovery factors of 70%, 75% & 80% were accepted, based on analogue cases. The unreached reservoir levels remain as Prospects and are discussed in the next section of this report.

Hardy 31 EE024430


FIGURE 1.10

GS-OSN-1 MAP

GS01-M1

Plugged & Abandoned

Discovery

Prospects

B-1

Prn-1

A-1

Hardy 32 EE024430


FIGURE 1.11

GS-01 3D AREA DEPTH STRUCTURE MAP AT TOP BASSEIN FORMATION

A1

S1

B2

B1

Prn1

0 10 Km

C.I. = 20m

Possible arcuate trendof reefal build up

Gas/Condensate Discovery

Depth Contour (metres subsea)

LEGEND

Gas Shows

Proposed Well Location

Plugged & Abandoned

Source: Hardy

Fig 1.12

Hardy 33 EE024430


TABLE 1.5

GS-01 SUMMARY OF GROSS AND NET GAS CONTINGENT RESOURCES AS AT 31st DECEMBER, 2010

Gross Contingent Resources BCF

Hardy Interest

(%)

Net Hardy Contingent Resources BCF

1C 2C 3C 1C 2C 3C

GS-01- B1area 50.5 83.0 133.2 10 5.1 8.3 13.3 Total GS-01 50.5 83.0 133.2 10 5.1 8.3 13.3 Notes: 1. The Net Hardy Contingent Resources on this table are only indications of Hardy’s working interest fraction of the



TABLE 1.6

GS-01 SUMMARY OF GROSS AND NET GAS CONDENSATE CONTINGENT RESOURCES AS AT 31st DECEMBER, 2010

Gross Contingent Resources MMBbl

Hardy Interest

(%)

Net Hardy Contingent Resources MMBbl

1C 2C 3C 1C 2C 3C

GS-01- B1area 1.12 1.85 2.97 10 0.11 0.19 0.29 Total GS-01 1.12 1.85 2.97 10 0.11 0.19 0.29 Notes: 1. The Net Hardy Contingent Resources on this table are only indications of Hardy’s working interest fraction of the



Hardy 34 EE024430


1.2.1.2 Prospective Resources GS-01-B1 Deep Prospects Because GS-01-B1 did not reach all prospective intervals, a first deeper Miocene prospect, trapped by stratigraphic pinch out and has a top seal of a 50 m thick shale sequence remains. A second deeper prospect with similar trap style as the first is a suggested Upper Oligocene carbonate build-up. Its reservoir parameters were predicted from PSDM, inversion and bandwidth extension data, as being similar to the nearby B-192 field. Low, Best and High estimates of GIIP for these B1 Prospects are 48, 90 and 157 BCF for the deeper Miocene, and 136, 213 and 324 BCF respectively for the Oligocene limestone reservoir. GCA has verified Hardy’s GCoS estimates and accepts them as 30% for the deeper Miocene, and 20% for the Oligocene prospect. The estimated Prospective Resources are shown in Table 1.8.

FIGURE 1.12

BLOCK GS-01 SEISMIC LINE THROUGH THE B-1 AND A-1 LOCATIONS

GS-01-A1 Deep Prospect GS-01-A1 was drilled by RIL and Hardy in 2006. All the five main targets of GS-01-A1 well proved tight (low permeability) although two were gas bearing, but the highest gas saturations occurred in an unexpected basal sandstone beneath the Panna limestone. Flow testing was not possible due to limitations of the drilling rig which was operating in HP/HT conditions 300+m deeper than prognosis. The well reached TD at 4,374 m MD and was suspended. Maps of Top Panna limestone show a very well developed four-way dip closure with relief of more than 100 m. Below, at Top Basement, a smaller four-way dip closure of over 60 m was mapped suggesting that a structural feature exists. No gas/liquid contact was intersected in the GS-01-A1 well but there is seismic brightening downdip of the discovery. Mapping on Top Basal

Well B-1 Well A-1

Secondary source kitchen

Basal clastics

Reefal Build-ups

Main source kitchen

NNE SSW

10 km

(approx)Source: Hardy

Hardy 35 EE024430


Sand with suitable scale has not been presented to GCA and AVO studies investigating the presence of stratigraphically trapped gas vs. lithology or tuning have not yet been made available to Hardy (and would be difficult at this depth). GCA audit of the A1 Basal Clastics area is based only on the seismic cross-section and map provided by Hardy. Analogue data from D-33, D-31 and B-192 near Block GS-01, which produce hydrocarbons from the Eocene Basal Clastics, were used by Hardy to predict the reservoir parameters. GCA accepted Hardy’s estimates of Low, Best and High GIIP for the A1 Basal Clastic prospect of 283, 446 and 698 BCF respectively. GCA considered Hardy’s estimated Prospective Resources as reasonable. These are summarised in the Tables 1.7 and 1.8. Prn1 Prospect Prospect Prn1 lies a little over 10 km North East of well GS-01-A1 (Figure 1.11). The seismic expression of the Oligocene carbonates appears similar to A1 with a high-amplitude reflection down-dip of a minor drape / shelf margin feature. In the light of the result at well A-1, where all the targets proved barren, this Prospect has been downgraded and GCoS is assessed as under 10%.

A Deeper Eocene, age prospect remains. GCA accepted the estimates of GIIP for the Prn1Oligocene Prospect as 18, 33 and 76 BCF for the Low, Best and High estimates respectively with slightly more (26-57-120 BCF) at Eocene. The estimated Prospective Resources are shown below.

TABLE 1.7

GS-01 PROSPECTS – SUMMARY OF GROSS GIIP (BCF)

Prospect Play Low Estimate Best Estimate High Estimate

B1 Deeper Miocene 48.0 90.0 157.0

B1 Oligocene 136.0 213.0 324.0

A1 Basal Clastics(Panna) 283.0 446.0 698.0

Prn1 Oligocene 18.0 33.0 76.0

Prn1 Eocene 26.0 57.0 120.0

Note: 1. It is inappropriate to focus on any of these volume postulations other than the ‘Best Estimate’.

Hardy 36 EE024430


TABLE 1.8

SUMMARY OF GS-01 GROSS AND NET GAS PROSPECTIVE RESOURCES FOR PROSPECTS AS AT 31st DECEMBER, 2010

Licence Prospect


Hardy W.I. (%)


GcoS (%)

BCF BCF

Low Estimate

Best Estimate

High Estimate

Low Estimate

Best Estimate

High Estimate

GS-01 B1 / Deeper

Miocene 34.0 68.0 126.0 10 3.4 6.8 12.6 30

GS-01 B1 /

Oligocene 95.0 160.0 259.0 10 9.5 16.0 25.9 20

GS-01 A1 198.0 335.0 558.0 10 19.8 33.5 55.8 25

GS-01 Prn1 / Oligocene

9.0 19.8 53.2 10 0.9 2.0 5.3 10

GS-01 Prn1 / Eocene

13.0 34.2 84.0 10 1.3 3.4 8.4 10

Notes:

1. The B1 Oligocene Time Map provided by Hardy, shows the structure to have a regional dip to the North-East. 2. The B1 Oligocene thickness range could not be confirmed by GCA due to lack of supporting data. Remaining

parameters were considered to be reasonable. 3. A1 Basal Clastics Area derived from the seismic cross-section from Presentation, as aerial map not provides with

suitable scale, but numbers reached were close enough to those of Hardy’s. 4. Independent validation was undertaken on the GcoS which verified Hardy’s numbers. 1.3 Krishna Godavari Basin The Krishna Godavari basin is located in eastern India and covers an area of about 45,000 km2, approximately 50% of which lies onshore and 50% offshore. The basin is aligned North East-South West, and slopes south-eastwards down the passive margin into the deep water of the Bay of Bengal. Hardy has working interests in two deep-water Blocks; Blocks D3 and D9 (Figure 1.13). The Krishna Godavari Basin began to form during Permian rifting and is filled with a clastic succession of Permian to Jurassic age sediments. These filled the incipient rift valley and local topographic lows and were overlain by a Lower Cretaceous transgressive sedimentary wedge. Since the Cretaceous, Krishna-Godavari has become a pericratonic basin. The South-Eastern part of the basin became a major Tertiary depositional centre as NE trending Precambrian lineaments were reactivated during the early Palaeocene, stepping down to the South East. Delta progradation to the South East has been ongoing since the Palaeocene, filling in remaining topographic lows. Sandstone reservoirs embedded within Lower and Upper Cretaceous source shale beds have been found to contain both oil and gas, as have Lower Eocene sandstones that overlie Palaeocene source beds (Figure 1.14). The main reservoir is the Ravva Sandstone of Miocene-Pliocene age.

Hardy 37 EE024430


FIGURE 1.13

LOCATION MAP SHOWING D3 AND D9 LICENCES


Sri Lanka

nnnnnnnnn





Bhutan

Myanmar


BangladeshBangladeshBangladeshBangladeshBangladeshBangladeshBangladeshBangladeshBangladesh Oil Field

LEGEND

Gas Field

Basin Limits

Gas Condensate Field


Hardy 38 EE024430


FIGURE 1.14

BLOCKS D3/D9 CENOZOIC STRATIGRAPHY

Source: Hardy/GCA

In addition to the Cretaceous and Palaeocene source rocks, gas prone Lower Eocene shales with TOC of up to 4%, have generated hydrocarbons since the early Miocene. However, the main source rock in the deep water is thought to be Miocene Godavari Clay, matured by an abnormally high geothermal gradient.

Structural traps exist in the basin in the form of tilted fault-blocks and rollover anticlines, though

they are usually modest in size. Stratigraphic trapping elements, includes erosional channels, updip pinchouts, unconformities. Permeability barriers are of great importance. The shale-dominated section (see the lithostratigraphic column of Figure 1.14) provides a strong regional seal. A thick Middle Eocene carbonate is an additional seal for Cretaceous and Lower Eocene reservoirs.

In the shallow water and onshore, discoveries are a mixture of oil fields, gas and gas condensate (Figure 1.13) however in deep water the only hydrocarbons yet found in fields, discoveries or shows are gas. This is likely to be due to the deeper burial of source rocks in the deep water section, leading to overmaturity of the source rock or generation of biogenic gas within the sediment column. The only evidence of oil in the petroleum system to date is a single thin-section fluid inclusion in the analysis run on Hardy’s KG-D9-A1 core. The oil sample was of unknown specific gravity. The remaining samples were all dry gas, in a gas-prone kerogen background. There is not yet compelling evidence to predict large oil accumulations in the D3 and D9 deepwater Blocks although this inclusion is encouraging.

VadaparuShale

(Source & Seal) > 2500

> 1200

> 2000

Thickness (m)

GodavariClay

(Seal)

PrincipalSedimentary

Cycle

Regional tectonic events

Age Formation Lithology

Palaeocene

Eocene

Oligocene

Miocene

Pliocene

Holocene

Pleistocene Regression

Transgression

Transgression

Transgression

Regression

Regression

Collision of

Indian and

Eurasian Plates

Collision of

Indian and

Tibetan Plates

Hardy 39 EE024430


1.3.1 Block D3 (Hardy NWI 10%)

The block measures 3,288 km2 in area, with water-depths varying from North West to South East between 400 m and 2,200 m. The block was under a 4 year work programme which ended in December, 2009 with a commitment to acquire 2,100 km2 3D seismic and drill 6 exploration wells. An extension to June, 2010 was granted by the GOI pursuant to various delays. At the Effective Date of this CPR four exploration wells had been drilled and four gas discoveries made. Due to the non-availability of suitable deep water rigs in the international market, the Phase 1 exploration programme has been extended until June, 2013 during which time the remaining two commitment wells will be drilled and the PSTM will be reprocessed to PSDM. Since the 2010 CPR, the W1 discovery has been made, further analysis of the R1 discovery has been undertaken and additional Prospects have been added to the corporate inventory. These are mostly structural targets although with additional stratigraphic targets as discussed below. Some of these Prospects have stemmed from the interpretation of the PSTM seismic cube acquired over the phase 2 area. The company has not yet completed the electromagnetic analysis over this second area.

The key plays identified in Block D3 are Pleistocene, Pliocene, Miocene, Oligocene, Eocene and Palaeocene. Exploration methodology in Blocks D3 is driven primarily by the identification of seismic amplitudes anomalies. Thirty five features based upon amplitude anomalies have so far been identified. Amplitude extraction maps were provided to GCA for validation. A further four structural traps have recently been identified (Figure 1.15).

FIGURE 1.15

D3 PROSPECT AND LEAD MAP

Source: Hardy/GCA

Appraisal Area(750 Sq.Km.)

B1 WellA1 Well

R1 Well

W1 Well

G1

QA1 Sand1

T1

Proposed Well

Z1

D1

P1

K1

H1

M1

J1

F1

U1 Sand 2

U1 Sand 1S1

S2

L1

E1

U2 Sand

R1

MM1

0 10 20km

QA1 Sand2

Gas Discovery

QTs

QTuQSu

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Previously, GCA has conducted a play fairway analysis over the D3 Block. The methodology used, established the basin architecture and a sequence stratigraphic framework, thereby enabling an understanding of the petroleum system and the key influences upon reservoir and seal distribution. The discovery wells on Block D3 provided a stratigraphic tie to the Pliocene and Pleistocene sequences. The study highlighted that the basin as a whole is relatively under-explored in terms of testing the various play-types that may exist and further work to place Leads and Prospects in a play context may generate additional Leads and Prospects to those currently identified by Hardy. GCA recognises that this play analysis approach has, over the past year, resulted in the successful test of the Miocene play in the W1well. The W1 well, drilled since the 2010 CPR was declared a Pliocene gas discovery. The A1 well is a Pleistocene discovery whilst the B1 well is a discovery in both the Pleistocene and Pliocene sequences. R1, which is located in the southern part of the block was drilled in 2009 targeting a seismic amplitude anomaly. The well made discoveries in three Miocene laminated sandstone reservoirs. The reservoirs are interpreted to have been deposited as amalgamated channels with well defined massive sands but with inter-channel areas which are very shale prone. Sands are thin and may be found below log resolution. These discoveries are discussed in the next section. Most of the Pliocene and Pleistocene discoveries are of biogenic gas but there is evidence of thermogenic gas in the D3 area too, from surface geochemistry studies. This is shown from data such as Surface Geochemical Exploration (Figure 1.16). Future discoveries containing thermogenically derived gas may possibly yield some condensate fraction.

FIGURE 1.16

SURFACE GEOCHEMICAL EVIDENCE FOR THERMOGENIC HYDROCARBONS

Source: Hardy

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1.3.1.1 Contingent Resources

The Contingent Resources of Block D3 are four discoveries: three made prior to 2010 in the Pleistocene, Pliocene and Miocene by wells A1, B1 and R1 as discussed below and shown on Figure 1.15. In 2010 the well W1 discovered gas in the Pliocene. W1 discovery, being new since previous CPRs is discussed first in the sections below. GCA understands that the Declaration of Commerciality for wells A1 and B1, and the Appraisal Proposal for R1 Discovery were submitted to the DGH in February 2011. GCA had earlier independently reviewed the seismic data and amplitude extract maps and estimated the in-place volumes related to the A1, B1 and R1 discoveries. GCA calculated its own P90, P50 and P10 area outlines for each of the discoveries using the amplitude extract maps provided by Hardy. GCA based its estimation of the recovery efficiency from the A1 and B1 sands on the MDT measurement of the pressure and the gas properties that were integrated with some assumed abandonment pressures between 500 and 1,000 psi. Tables 1.9 and 1.10 summarize the GIIP and the Contingent Resources for Block D3 discoveries.

Discovery W1 Exploration well W1 targeted a deep water channel lobe complex interpreted to be Pliocene in age. The channel lobe complex was gas bearing in two 8 m intervals (Figure 1.17). A deeper 1m net gas sand was also encountered although this is too small to contribute to contingent resources. GCA has reviewed the post-well analysis performed by RIL and Hardy and re-examined the seismic attribute maps used as the basis of well-planning and resource estimation. The two gas sands are both thin (from the top of Sand 1 to base of Sand 2 is only 30 m), which is within a seismic cycle at these depths (Figure 1.18) (seismic cycle length = 40 m). GCA consequently believes that the two pre-drill amplitude maps do not represent Sand 1 and Sand 2 individually, particularly as they have been derived with large seismic windows, and thus should be combined in one areal extent. GCA believes resources should be computed based on a single map for both intervals and in this case the most appropriate map is the upper, Sand 1 map, perhaps with a smaller time window such as 0-50 m which defines the channel edge more sharply, but at the same location.

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FIGURE 1.17

WIRELINE LOG RESPONSES AT W1 DISCOVERY

Source: Hardy GCA considers that the W1 discovery has uncertainty in its areal extent due to the low resolution of seismic mapping, the elongate geometry of the field and the difficulty of distinguishing water-bearing, from gas-bearing sands. The volumes quoted for W1 discovery allow for a range of areal extents at P90 to P10 with P50 determined by lognormal distribution. Recognising the tighter areal constraints and the off-axis location of the well in Sand 1, the revised Sand1 reservoir thicknesses and parameters allow for enhanced properties beyond those found at the well. There is also some up-dip prospectivity near the channel which cannot be considered contingent.

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FIGURE 1.18

REVISED SAND 1 AMPLITUDE MAP (MAIN SEGMENT)

Source: GCA

Dhirubhai 39 Well A1 is located in water depth of 715 m. On the basis of MDT results and petrophysical analysis, A1 encountered two gas zones designated as Pleistocene Sands 0 and 1. The DST test of Sand 1 produced gas at a maximum rate of 38.05 MMscfd in the interval 1,565 – 1,585 mBRT. The produced gas was dry with a gravity of 0.57 at standard conditions. Results of the pressure transient analysis indicate a permeability range from 2,700 mD to 3,800 mD and an estimated static reservoir pressure of 2,554.3 psi (at gauge depth of 1,509.2 mBRT) and reservoir temperature of 114 deg F. GCA’s review verifies the results of well A1 DST and supports its transient pressure analysis procedure.

P10 polygon

P90 polygon

Well W1

0 1 km

Further prospectivity

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Dhirubhai 41 Well B1 is located at a water depth of 711 m, and was drilled to a total depth of 2,730 mBRT. It encountered gas in two intervals in the Pleistocene (Pleistocene Sand 2 – Southern) and one interval in the Pliocene (Pliocene Sand). No DST was performed in this well.

In the A1-B1 area the operator (RIL) has been reviewing the connectivity between the existing discovery wells and the AP1 Prospects. Near and Far Stack difference volumes do show a strong response at both the AP1 location and the A1 discovery well which is supporting evidence for hydrocarbon bearing sands at both locations. It is GCA’s interpretation that these sands are both sourced from the North West and charged likely from the South East and GCA’s firm conclusion that lateral connectivity between the two is unproven and unlikely. The bright ‘sand’ reflectors fade away and are also heavily faulted (Figure 1.19). The same is true on all attribute volumes examined, including the Vp/Vs cube. For that reason GCA keeps the A1& B1 contingent resources separate from prospectivity at AP1.

FIGURE 1.19

LACK OF CONNECTIVITY BETWEEN WELL -A1 AND PROSPECT AP1

Source: Hardy/GCA

Dhirubhai 44 Well R1 is located at water depth of 1,982.5 m, and was drilled as a directional well with a total depth of 4,113 m TVDSS. A Formation testing tool, Reservoir Characterization Instrument (RCI), was run. Three gas samples and one water sample were collected. A gas gradient of 0.12 psi/ft was established in the upper zone (3,832-3,853 m TVDSS) and a water gradient of 0.44psi/ft was established in the lower zone (3,939.9-3,966.7 m TVDSS). Gas composition showed C1 of 98.33 – 99.4 mole% and a gas gravity of around 0.56.

KGV -D3-A1 AP1 SW NE

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TABLE 1.9

BLOCK D3: SUMMARY OF GROSS GIIP FOR DISCOVERIES AS AT 31st DECEMBER, 2010

Gross GIIP (BCF)

Low Estimate 1C

Best Estimate 2C

High Estimate 3C

W1 Pliocene Sands 145 232 369 Total W1 145 232 369 A1 Pleistocene Sand 0 41.0 163.0 388.0 A1 Pleistocene Sand 1 48.0 140.0 296.0 Total A1 89.0 303.0 684.0 B1 Pleistocene Sand 2 (Southern)

84.0 209.0 450.0

B1 Well Pliocene Sand 40.0 96.0 175.0 Total B1 124.0 304.0 625.0 R1 Sand 1 (Miocene) 21.0 30.0 39.0 R1 Sand 2 (Miocene) 42.0 53.0 68.0 R1 Sand 3 (Miocene) 35.0 54.0 77.0 Total R1 98.0 137.0 184.0 Total D3 456.0 976.0 1,862.0

TABLE 1.10

BLOCK D3: SUMMARY OF GROSS AND NET GAS CONTINGENT RESOURCES FOR DISCOVERIES AS AT 31st DECEMBER, 2010


BCF Hardy

Interest

Net Hardy Contingent Resources

BCF 1C 2C 3C 1C 2C 3C

W1 Pliocene Sands 101.5 162.4 258.3 10 10.2 16.2 25.8 Total – W1 101.5 162.4 258.3 10 10.2 16.2 25.8 A1 Pleistocene Sand 0 28.0 113.0 274.0 10 2.8 11.3 27.4 A1 Pleistocene Sand 1 33.0 97.0 209.0 10 3.3 9.7 20.9 Total A1 61.0 210.0 483.0 10 6.1 21.0 48.3 B1 Pleistocene Sand 2 (Southern)

57.0 146.0 316.0 10 5.7 14.6 31.6

B1 Well Pliocene Sand 27.0 67.0 125.0 10 2.7 6.7 12.5 Total B1 84.0 213.0 441.0 10 8.4 21.3 44.1 R1 Sand 1 (Miocene) 15.0 21.0 28.0 10 1.5 2.1 2.8 R1 Sand 2 (Miocene) 30.0 38.0 49.0 10 3.0 3.8 4.9 R1 Sand 3 (Miocene) 25.0 39.0 55.0 10 2.5 3.9 5.5 Total R1 70.0 98.0 132.0 10 7.0 9.8 13.2 Total D3 316.5 683.4 1314.3 10 31.7 68.3 131.4 Notes: 1. The Net Hardy Contingent Resources on this table are only indications of Hardy’s working interest fraction of the



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1.3.1.2 Prospective Resources GCA’s workflow for volumetric estimation for stratigraphic targets is probabilistic. The criteria used by GCA for amplitude extraction and subsequent identification of the areal extents (P90, P50 and P10) used in the volumetrics are:

Absolute magnitude of seismic amplitude, relative to well calibrations; Consistency of seismic amplitude magnitude across the areas to define the Low (P90), Best

Estimate (P50) and High Estimate (P10) probability range; and Morphology of seismic amplitudes as related to environment of deposition. This approach was consistently applied throughout validation of each amplitude event. For structural targets a probabilistic approach is still taken but GCA’s estimation of areal extent allows for uncertainty in the depth conversion of time surfaces to depth which would affect spill points, and for structures to be compartmentalised (where appropriate) or not filled to spill. Reservoir parameters are a range of realistic averages across the whole target. New Prospects and Leads added to the prospect inventory since the 2010 CPR are described in some detail below. New Prospects and Leads include QT/QS, which are structural and stratigraphic Leads in the area of the new seismic dataset and MM1, a structural Prospect in the existing study area. QT and QS AREA South East of the existing discoveries Hardy has begun interpreting the new area of 3D seismic data acquired in 2009 and has identified some structural targets in thrusts (Figure 1.20). These features are at an early stage of the exploration workflow, having been identified and mapped on the PSTM cube but further work is anticipated prior to drilling (such as re-mapping on the PSDM volume once reprocessing is complete, depth conversion, fault seal analysis etc). They are classified as Leads, but with little additional work, could soon be elevated to Prospect status. GCA has found good consistency between its own and Hardy’s GIIP estimates for these Leads. Pliocene QTu Pliocene QTu is the youngest Lead in this area and is located in a backthrust rollover. There is structural closure bounded by faults to the North East and South West. GCA notes that there is some fault segmentation of the structure at the crest so reduces area slightly over that initially proposed, but it remains a valid prospect. Being stratigraphically younger, the range of reservoir properties is slightly better than those found in the nearby Miocene sands. Miocene QTu Miocene QTu is an upthrown fault block which has structural closure in the time domain. GCA has reviewed the volumetric parameters used by Hardy to quantify this prospect and has only revise slightly down the P90 area. Miocene reservoir parameters are consistent with those found in the R1 discovery well to the west. Miocene QTs Miocene QTs is the downthrown unit below the QTu Lead. It should be possible to test both targets with the same well. The reservoir properties are predicted to be very similar to QTu, although the size of trap is smaller and with greater uncertainty.

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An additional stratigraphic target (QSu) below the main thrust/Miocene unconformity was proposed. There is no structural closure at this level. A bright amplitude consistent with an increase in acoustic impedance is noted from RMS mapping around this interval. Using the relaxed amplitude cut-offs shown, there is a high chance of leakage into adjacent sands, so GCA has restricted the area to the very brightest amplitude response which might be taken as having the best sand quality. No analysis as to potential fluid fill has yet been done on these Q Leads, nor have they been mapped in depth. Both steps would be expected to be completed prior to drilling.

FIGURE 1.20

SEISMIC SECTION THROUGH THE ‘Q’ LEADS

Source: GCA

0 4 km

A

A’

3s TWT

Pliocene

MioceneSub Unconformity(QSu) Subthrust

(QTs)

Upthrust(QTu) 4s TWT

A A’

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MM1 MM1 is a Miocene combination Prospect on a ridge extending East West in the centre of the D3 Block. Based on the PSDM migration there is a 5 km2 closure in depth at the Miocene ‘Deep 4’ level, increasing for older units. Sands of Miocene age have been found in the nearby R1 well. Bright amplitudes suggest discrete sand bodies draped over this palaeo-high (Figure 1.21).

FIGURE 1.21

SEISMIC SECTION ALONG THE MM1 PROSPECT WITH POTENTIAL CHANNELS

Source: GCA

SW NE

R1

0 2 km

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GCA suggests that traps in this area are structural-stratigraphic combination traps. The strongest amplitudes are likely channel systems draped over the structural closures (Figure 1.22). Hardy intends to test this structure during the 2011 drilling campaign. Volumetrically, there is a wide range of Prospective Resources associated with this feature. The potential sands appear to be channelized rather than sheet like. GCA’s low case is for a single channel segment overlying the structural closure to be hydrocarbon bearing. However, given the region is dipping generally to the south east, there is potential for stratigraphic trapping in some of the down-dip extensions beyond the 4-way dip closure. Analysis has shown several sequences of Miocene channels draped over the structure. The inter-relationships of the channels is likely to be complex so careful well design is required to maximise the number of potential sands and thereby volumes intersected. Existing Prospects GCA has sufficient data to validate the resource volumes of the Prospects in the 3D seismic area. GCA reviewed the 3D seismic data and the relevant well data for the A1, B1, R1 and W1 wells to use as benchmarks and calculated the probabilistic volumetric resource estimates.

The anomalies reviewed, by GCA in Block D3 are associated with high seismic amplitudes in the Plio-Pleistocene geologic section. In general, the relative size of the individual horizon amplitude identified Prospects are small, averaging some 9 km2 and ranging between 4 to 16.4 km2. The Pleistocene and Pliocene gas sand responses as defined by petrophysics in the A1, B1 and R1 wells are calibrated to their respective seismic amplitude responses at the well locations. These calibrated seismic amplitude responses are extrapolated away from the well bore to identify areas of similar gas sand occurrence. Results from recent technical evaluations that includes reprocessing of 3D seismic data (work in progress), will modify the seismic amplitude methodology and the assumptions used. Hardy provided an AVO analysis performed including fluid factor analysis, fluid substitution models generated and seismic inversion. This was used, in conjunction with other seismic attributes to guide volumetric estimates. According to the report, the Pleistocene Sands 1 and 2 exhibit a polarity reversal, increase amplitude with offset, and is a Class III anomaly. The Pliocene gas sand exhibits a polarity reversal and was designated as a Class III anomaly. GCA independently validated these conclusions using the data provided by Hardy. GCA performed probabilistic volumetric calculations using Crystal Ball and applying the Low-Best-High Estimates range of reservoir parameter values in a triangular distribution. The Prospective Resources attributed to D3 are shown in Table 0.7 of the Summary section and in Table 1.12 below. A summary of the Low Estimate (P90), Best Estimate (P50), and High Estimate (P10) GIIP values are listed in Table 1.11. GCA has previously reviewed the GCoS for the Prospects identified by Hardy in Block D3.

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TABLE 1.11

BLOCK D3: SUMMARY OF GROSS GIIP FOR PROSPECTS AS AT 31st DECEMBER, 2010

Prospect Play

Gross GIIP (BCF)

Low Estimate

Best Estimate

High Estimate

B1 Pleistocene Sand 2 (Central) Pleistocene 43.0 184.0 472.0 B1 Pleistocene Sand 2 (Northern)

Pleistocene 107.0 367.0 867.0

F1 Pleistocene Pleistocene 130.0 391.0 834.0 G1 Pleistocene Pleistocene 298.0 426.0 568.0 K1 Pleistocene Pleistocene 177.0 592.0 1,249.0 P1 Pleistocene Pleistocene 119.0 431.0 992.0 D1 Pliocene Pliocene 30.0 56.0 89.0 E1 Pliocene Pliocene 107.0 244.0 450.0 L1 Pliocene Pliocene 78.0 193.0 370.0 U1 Sand 1 Pliocene Pliocene 76.0 191.0 404.0 U1 Sand 2 Pliocene Pliocene 107.0 231.0 431.0 QA1 Sand 1 Pliocene Pliocene 143.0 241.0 385.0 U2 Sand Pliocene Pliocene 103.0 240.0 453.0 S1 Sand 1 Pliocene Pliocene 57.0 98.0 152.0 S1 Sand2 Pliocene Pliocene 73.0 100.0 141.0 T1 Pliocene Pliocene 75.0 107.0 148.0 G1 Miocene Miocene 157.0 459.0 939.0 J1 Miocene Miocene 189.0 390.0 722.0 M1 Miocene Miocene 247.0 646.0 1,259.0 MM1 Miocene Miocene 272.0 554.0 922.0 QA1 Sand 2 Miocene Miocene 289.0 444.0 659.0 R1 Sand Miocene Miocene 32.0 54.0 80.0 W1 Sand 3 Miocene Miocene 165.0 265.0 398.0 H1 Oligocene Oligocene 468.0 1,170.0 2,274.0 Z1 Oligocene Oligocene 125.0 415.0 966.0 Note: 1. It is inappropriate to focus on any of these volume postulations other than the ‘Best Estimate’.

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TABLE 1.12

BLOCK D3: SUMMARY OF GROSS AND NET GAS PROSPECTIVE RESOURCES FOR PROSPECTS AS AT 31st DECEMBER, 2010

Prospect

Gross Prospective Resources Hardy W.I. (%)

Net Hardy Prospective Resources GCoS

(%) BCF BCF

Low Estimate

Best Estimate

High Estimate

Low Estimate

Best Estimate

High Estimate

B1 Pleistocene Sand 2 (Central)

30.0 127.0 330.0 10 3.0 12.7 33.0 80

B1 Pleistocene Sand 2 (Northern)

73.0 255.0 614.0 10 7.3 25.5 61.4 80

F1 Pleistocene 88.0 272.0 589.0 10 8.8 27.2 58.9 80

G1 Pleistocene 206.0 297.0 400.0 10 20.6 29.7 40.0 80

K1 Pleistocene 123.0 410.0 879.0 10 12.3 41.0 87.9 80

P1 Pleistocene 83.0 300.0 691.0 10 8.3 30.0 69.1 80

D1 Pliocene 21.0 39.0 62.0 10 2.1 3.9 6.2 70

E1 Pliocene 75.0 169.0 319.0 10 7.5 16.9 31.9 70

L1 Pliocene 53.0 134.0 262.0 10 5.3 13.4 26.2 70

U1 Sand 1 Pliocene

52.0 134.0 291.0 10 5.2 13.4 29.1 70

U1 Sand 2 Pliocene

74.0 161.0 306.0 10 7.4 16.1 30.6 70

QA1 Sand 1 Pliocene

98.0 168.0 270.0 10 9.8 16.8 27.0 70

U2 Sand Pliocene

72.0 166.0 318.0 10 7.2 16.6 31.8 70

S1 Sand 1 Pliocene

39.0 68.0 104.0 10 3.9 6.8 10.4 70

S1 Sand2 Pliocene

50.0 70.0 100.0 10 5.0 7.0 10.0 70

T1 Pliocene 52.0 75.0 105.0 10 5.2 7.5 10.5 70

G1 Miocene 112.0 328.0 675.0 10 11.2 32.8 67.5 70

J1 Miocene 135.0 281.0 524.0 10 13.5 28.1 52.4 70

M1 Miocene 175.0 464.0 904.0 10 17.5 46.4 90.4 70

MM1 Miocene 191.0 388.0 645.0 10 19.1 38.8 64.5 70

QA1 Sand 2 Miocene

204.0 308.0 455.0 10 20.4 30.8 45.5 70

R1 Sand Miocene

23.0 38.0 58.0 10 2.3 3.8 5.8 70

W1 Sand 3 Miocene

117.0 190.0 282.0 10 11.7 19.0 28.2 70

H1 Oligocene 334.0 840.0 1,641.0 10 33.4 84.0 164.1 24

Z1 Oligocene 89.0 300.0 703.0 10 8.9 30.0 70.3 24




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TABLE 1.13

BLOCK D3: SUMMARY OF GROSS GIIP FOR LEADS AS AT 31st DECEMBER, 2010

Lead Play Gross GIIP (BCF)

Low Estimate

Best Estimate High Estimate

QTu Pliocene - 556 - QTu Miocene - 184 - QTs Miocene - 177 - QSu Miocene - 194 - Notes: 1. It is inappropriate to focus on any of these volume postulations other than the ‘Best Estimate’.

TABLE 1.14

BLOCK D3: SUMMARY OF GROSS UNRISKED GAS PROSPECTIVE RESOURCES FOR LEADS AS AT 31st DECEMBER, 2010

Lead Play Gross Unrisked Prospective Resources (BCF)

GCoS (%) Low

Estimate Best

Estimate High

Estimate QTu Pliocene - 389.2 - 17 QTu Miocene - 128.8 - 17 QTs Miocene - 123.9 - 17 QSu Miocene - 135.8 - 15 Notes: 1. The Geologic Chance of Success (GCoS) reported here represents an indicative estimate of the


2. It is inappropriate to report summed-up Prospective Resource volumes or to otherwise focus upon those of other than the ‘Best Estimate’.

1.3.2 Block D9 (Hardy NWI 10%)

Block D9 is located offshore the east coast of India (Figure 1.13). It covers an area of 11,605 km2 in water depths ranging from 2,400 m in the North West to 3,150 m in the South East of the block. Hardy has a 10% interest with Reliance Industries owning the remaining 90% and operatorship. The block is under an eight year (3 phases) exploration programme which started in April, 2003 with a phase 1 commitment to acquire 2D & 3D seismic and drill 4 exploration wells. The phase 1 seismic commitment was for 2,100 km of 2D and 1,650 km2 of 3D. To date 2,087 km 2D seismic, 4,188 km2 3D seismic & 4 (196 km) controlled source electromagnetic (CSEM) lines have been acquired. This is considered to have met the minimum work requirement regarding seismic acquisition. In addition, 570 km of 2D seismic is available from the old (1997) exploration activities. Exploration well KG-D9-A1 was drilled in 2009 and B3 in 2010. Well B3 found gas shows and good reservoir but no discovery (Figure 1.14). The results of this well have reduced the source and reservoir risks on some of the D9 Prospects. A remaining four wells have been approved for drilling to complete the minimum work obligations of the exploration phase. In December 2010, the operator applied to the Government for, and received, a 337 day extension to the Drilling Moratorium due to statutory delays.

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Exploration well KG-D9-A1 was drilled in 2009 to a TD of 4,875 m MD, reaching the Early Miocene. The well targeted an anticline which contained Prospects in the Lower Miocene, Middle Miocene, Upper Miocene and Palaeocene/Cretaceous but did not reach the Palaeocene/Cretaceous prospect. GCA was provided with composite and mud logs of the well. Despite being drilled on a structural closure the well did not find any hydrocarbon accumulations. GCA has reviewed the composite well log and concludes this largely due to a lack of reservoir, the well encountering ‘limestone’ formations at the Lower Miocene reservoir depths. These are interpreted as calc-lucite deposits in a turbiditic depositional environment. In addition, GCA notes that while there is significant dip closure on the target structure, closure in a strike direction is of shallow relief. Minor gas shows in the well confirms the presence of a possible biogenic gas source. There is not yet strong evidence from surface geochemical exploration for a thermogenic source in the D9 area.

FIGURE 1.22

D9 PROSPECT AND LEAD LOCATION MAP

0 10 Km

Source: Hardy

Lead and Prospect Map

Mid Miocene Lead

Cretaceous

Paleocene / Cretaceous

Lr. Miocene

Mid. Miocene

Up. Miocene

Pliocene

Pliocene

Cretaceous Prospects

Palaeocene/Cretaceous Prospects

Lower Miocene ProspectsMid Miocene Prospects and lead (labelled)

Upper Miocene Prospects

Pliocene Leads

Pliocene Leads

KG-D9-B3

KG-D9-A1

B2

A2

C1

B1

Gas Shows

Dry Hole

Clusters

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Depth maps were provided for validation of the structural anomalies. Additionally, some amplitude extraction maps were provided by Hardy. GCA validated the depth structure closures and confirms that the methodologies employed are according to industry standards and procedures. GCA believes that the 3D depth-migrated seismic data is a good representation of the depth structure and that the Prospects and Leads in D9 are predominantly structural driven with the exception of the five channel Leads. Edge, Similarity and Spectral attributes analysis is beginning to reveal the edge of sedimentary bodies and from analysis of images such as Figure 1.23 below an informed prediction of reservoir quality, type and geometry can be made. The B3 well found encouraging gas shows during drilling and excellent reservoir, consistent with its location in the centre of a wide Pliocene channel’s meander. Once applied more widely, this attribute work will help with defining and risking Prospects in D9 in future.

FIGURE 1.23

GEOMORPHOLOGY IN PLIOCENE D9 REVEALED BY SEISMIC ATTRIBUTES

Source: Hardy Work undertaken since the last CPR includes biostratigraphy and fluid inclusion studies of the Miocene section of the KG-D9-A1 well. A number of dry gas bearing intervals were found, along with both gas prone kerogen and a thermogenic sulphur signature. A single sample below the dry gas at 4,660 m MD was also found as an inclusion within a carbonate cement. These are both encouraging evidence for thermogenic generation in deeper kitchens however there is no evidence to suggest A1 is located on a major migration pathway. The Low Estimate, Best Estimate and High Estimate GIIP and STOIIP for Prospects and Leads are listed in the summary Tables 1.15 and 1.16 below. This is followed by a summary of the Gross

1 km

B3 well

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and Net gas and oil Prospective Resources for Prospects as Low, Best, and High Estimates (Tables 1.17 and 1.18) and a summary of the Gross and Net gas and oil Best estimate for Prospective Resources for Leads (Tables 1.19 and 1.20).

TABLE 1.15

BLOCK D9: SUMMARY OF GROSS GIIP FOR PROSPECTS/LEADS


Prospect/Lead Play Class Gross GIIP (TCF)

Low Estimate

Best Estimate

High Estimate

Channel Complex (C1) Pliocene Prospect 0.3 0.9 2.2 Northern Anticline (NW Flank B1)

U. Miocene Prospect 1.1 3.6 8.1

Central Anticline (NW Flank)

U. Miocene Prospect 0.6 1.5 3.0

Central Anticline (near B3) U. Miocene Prospect 1.4 3.6 7.6 Southern Anticline (SE Flank C1) U. Miocene Prospect 1.5 4.2 8.8

Northern Anticline B1 M. Miocene Prospect 1.9 3.7 6.4 Central Anticline (near B2) M. Miocene Prospect 1.8 2.7 3.8 Southern Anticline C1 M. Miocene Prospect 1.9 2.7 3.7 Northern Anticline (near B1)

L. Miocene Prospect 2.6 9.0 21.2

Central Anticline (near B2) L. Miocene Prospect 1.8 4.1 7.8 Central Anticline (near A2) L. Miocene Prospect 1.2 3.3 6.9 Channel Complex (A2) Pliocene Lead - 0.1 - Middle Miocene Channel M. Miocene Lead - 0.3 - Note:

1. It is inappropriate to focus on any of these volume postulations other than the ‘Best Estimate’.

TABLE 1.16

BLOCK D9: SUMMARY OF UNRISKED GROSS STOIIP FOR PROSPECTS/LEADS AS AT 31st DECEMBER, 2010

Prospect/Lead Play Class Gross STOIIP (MMBbl)

Low Estimate

Best Estimate

High Estimate

Central Anticline (4 way fault closure B2)

Palaeocene Prospect 460.0 1,320.0 2,930.0

Central Anticline (Fault Closure B2)

Cretaceous Prospect 140.0 390.0 800.0

Wedge Palaeocene Lead - 1,460.0 - Note:


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TABLE 1.17

BLOCK D9: SUMMARY OF GROSS AND NET GAS PROSPECTIVE RESOURCES FOR PROSPECTS AS AT 31st DECEMBER, 2010

Prospect

Gross Prospective Resources Hardy W.I. (%)


GCoS (%)

BCF BCF Low

Estimate Best

Estimate High

Estimate Low

Estimate Best

Estimate High

Estimate C1 Pliocene 210.0 630.0 1540.0 10 21.0 63.0 154.0 25 Northern Anticline (NW Flank B1) / U. Miocene

800.0 2,500.0 5,600.0 10 80.0 250.0 560.0 20

Central Anticline (NW Flank) / U.Miocene

400.0 1,100.0 2,100.0 10 40.0 110.0 210.0 20

Central Anticline (near B3) / U. Miocene

1,000.0 2,500.0 5,300.0 10 100.0 250.0 530.0 20

Southern Anticline (SE Flank C1) / U. Miocene

1,100.0 2,900.0 6,200.0 10 110.0 290.0 620.0 10

Northern Anticline B1 / M. Miocene

1,300.0 2,500.0 4,500.0 10 130.0 250.0 450.0 20

Central Anticline (near B2) / M. Miocene

1,300.0 1,900.0 2,700.0 10 130.0 190.0 270.0 20

Southern Anticline C1/ M. Miocene

1,300.0 1,900.0 2,600.0 10 130.0 190.0 260.0 15

Northern Anticline (Near B1) / L. Miocene

1,800.0 6,300.0 15,000.0 10 180.0 630.0 1500.0 15

Central Anticline (near B2) / L. Miocene

1,300.0 2,800.0 5,500.0 10 130.0 280.0 550.0 19

Central Anticline (near A2) / L. Miocene

800.0 2,300.0 4,900.0 10 80.0 230.0 490.0 15




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TABLE 1.18

BLOCK D9: SUMMARY OF GROSS AND NET OIL PROSPECTIVE RESOURCES FOR PROSPECTS AS AT 31st DECEMBER, 2010




An estimate of the Prospective Resources for the Leads identified on Block D9 is summarised below.

TABLE 1.19

BLOCK D9: SUMMARY OF GROSS UNRISKED GAS PROSPECTIVE RESOURCES FOR

LEADS AS AT 31st DECEMBER, 2010

Lead Play

Gross Unrisked Prospective Resources (BCF) GCoS

(%) Low Estimate

Best Estimate

High Estimate

Channel Complex (A2) Pliocene - 70 - 20 Middle Miocene Channel M. Miocene - 210 - 10




Prospect


Hardy W.I. (%)


GCoS (%)

MMBbl MMBbl

Low Estimate

Best Estimate

High Estimate

Low Estimate

Best Estimate

High Estimate

Central Anticline (4 way fault closure B2) / Palaeocene

142.0 420.0 961.0 10 14.2 42.0 96.1 18

Central Anticline (Fault Closure B2) / Cretaceous

44.0 122.0 260.0 10 4.4 12.2 26.0 18

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TABLE 1.20

BLOCK D9: SUMMARY OF GROSS UNRISKED OIL PROSPECTIVE RESOURCES FOR LEADS AS AT 31st DECEMBER, 2010

Lead Play Prospective Resources (MMBbl)

GCoS (%) Low

Estimate Best

Estimate High

Estimate

Wedge Palaeocene - 456.0 - 18




1.4 Assam-Arakan Basin

The Assam-Arakan Basin is located in North East India and covers about 115,000 km2. The first commercial oil was discovered in 1889 and since then several oil and gas fields have since been discovered in thrust sheets of the Assam-Arakan fold belt. In 1996, there were 38 oil fields and 1 gas field, each with more than 1 million barrels of oil equivalent production or proven reserves (USGS, 2004). Indeed, until the 1974 discovery of the Mumbai High Field, Assam-Arakan was the region with largest oil and gas production in India (USGS, 2004).

Assam-Arakan Basin comprises several elements each trending North East. Naga and Mirkir Hills are found in the South East. North West of these hills is the flat lying Assam Shelf and beyond that the Brahmaputra River and the Himalayan Foreland and mountains.

The Naga and Mirkir Hills are formed by tectonic compression on several NE-SW striking thrust faults (Figure 1.24). These have also formed the structures which form the traps for most of the fields in the area (anticlines and faulted anticlines). Further traps are found below the thrust sheets and the faults have caused elevated thermal maturity and vertical migration pathways.

The Assam Shelf (Basin) contains up to 7,000 m of Cretaceous to Recent alluvial and clastic sediments (Figure 1.25) overlying a crystalline and metamorphic basement. Interbedded with these clastic units are an Eocene limestone (Kopili Fm) and Oligocene (Barail Group) coals. The major oil accumulations are found in Oligocene and Miocene sandstones with additional minor production from limestones, shales and fractured granite in fields which are related to the trend of basement ridges. These reservoirs were deposited in environments ranging from delta front, distributary channels / point bar to fluvial deposits of a braided channel system.

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FIGURE 1.24

OIL FIELDS SOUTH OF BRAHMAPUTRA RIVER AS-ONN-2000/1

Source: Hardy

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FIGURE 1.25

STRATIGRAPHIC COLUMN ASSAM-ARAKAN BASIN

Source rocks are likewise present throughout the geological section, typically with low TOC but good thermal maturity, increasing to the South East. The known petroleum systems that exist in the area are the Sylhet-Kopili and Barail-Tipam units as seen in the Formation, Source, Reservoir, Seal and Oil and Gas columns of Figure 1.18. Both regional and local cap rocks are present.

Source: ONGC

Note: Stratigraphic column downloaded f rom ONGC website. Although the local geology may be dif ferent than the generalised geology shown here, it represents the key reservoirs.

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The trap types found in the Assam-Arakan basin are: Anticlines and faulted anticlines associated with ENE-WSW or NNE-SSW trends; Fault closures; Pinchouts; Fractured basement; and Stratigraphic sandstone lens traps. 1.4.1 AS-ONN-2000/1 (Hardy NWI 10%)

The AS-ONN-2000/1 Block measures 5,754 km2 and is located immediately north of the Brahmaputra River and south of the Eastern Himalaya (Figure 0.2). It is a frontier exploration block being further west and on the other side of the river from the existing, numerous hydrocarbon discoveries, in an area where there is currently very little data and the geological history is less well understood. There is some 2D seismic (vintage 124 km; new 391 km) of poor to locally fair quality in the shallow geologic section (Figure 1.26); regional gravity data, geochemical survey (work in progress) and environmental studies for well locations. A commitment to acquire more 2D and reprocess 1,020km is complete save for extra, optional, reprocessing.

FIGURE 1.26

SEISMIC LINE AS-17-08 IN ASSAM BLOCK

Source: Hardy

Source: Hardy

Namsang

Tipam

Sylhet

Basement

Gondwana?

0 10 km

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AS-ONN-2000/1 is operated by RIL who has a 90% interest in the block. Hardy has the remaining 10% interest. The block is held under a three phase programme. Phase 1 was a 3 year period from 10th January, 2008 through to 9th January, 2011. The minimum work commitment has been completed. RIL, however, has written to the Directorate General of Hydrocarbons on 10th December, 2010 asking for a six month extension period to complete further studies prior to deciding whether to enter Phase 2, which carries a one well obligation and ends in 9th January, 2013.

During GCA’s review in 2009, the following geo-technical issues were presented based on the known plays and potential new plays:

Complex structures in the block will require 3D seismic for proper imaging; Reservoir compartmentalization can be expected; and Relatively small to medium field size per analogue trends. Two Leads have been defined from the existing 2D seismic data; Gohpur is a faulted anticline and Rajabari is a horst block (Figure 1.27). GCA has reviewed the seismic data. The seismic quality is fair but the grid density is coarse (3 km to 5 km by 3 km). Leads Gohpur and Rajabari are each defined by 3 seismic lines.

FIGURE 1.27

AS-ONN-2000/1 PROSPECT AND LEAD LOCATION MAP

SYLHET FORMATION TIME STRUCTURE MAP

GOHPUR

RAJABARI

Source: Hardy 0 5 km

Hardy 63 EE024430


The reservoir rocks in AS-ONN-2000/1 are expected to be fractured granite basement, and sandstones throughout the geologic section. The targets are the Kopili, Sylhet, Tura and Bokabil Formations and the Middle Eocene Sylhet Formation that consists of interbedded limestone and siltstone.

It is GCA’s opinion that the additional DHI and facies attribute studies RIL/Hardy propose will have limited impact on the prospect viability when there is still a coarse seismic input dataset but reprocessing and seal related studies could reduce the risk for individual Leads. GCA reviewed the volumetric data supplied by Hardy and validated the parameters as needed. No additional material has been supplied since the 2010 CPR. It is the opinion of GCA that these Leads are high risk, but with moderate to large potential. Finding reservoir quality rocks and a working petroleum system are the major geological risks as nearby wells have apparently found no Barail (source and reservoir) or Girujan Clay (seal). Maturity studies have thus far shown thermal indices increasing to the South East, where the fields are more prolific, under the thrust sheets so long distance migration may be required. GCA estimates the GCoS is 10%, typical for a frontier exploration play. A summary of the estimated STOIIP and the Prospective Resources for Assam Leads is shown below:

TABLE 1.21

AS-ONN-2000/1: SUMMARY OF GROSS STOIIP FOR LEADS


Lead STOIIP (MMBbl)

Low Estimate Best Estimate High Estimate

Gophur - 67.0 - Rajabari - 15.0 - Note:


TABLE 1.22

AS-ONN-2000/1 : SUMMARY OF GROSS AND NET OIL PROSPECTIVE RESOURCES

FOR LEADS AS AT 31st DECEMBER, 2010

Lead

Gross Prospective Resources (MMBbl) Hardy

W.I. (%)

Net Prospective Resources (MMBbl) GCoS

(%) Low Estimate

Best Estimate

High Estimate

Low Estimate

Best Estimate

High Estimate

Gophur - 20.0 - 10 - 2.0 - 10 Rajabari - 5.0 - 10 - 0.5 - 10




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2. ECONOMIC EVALUATION NPVs have been calculated for the ‘Proved’, ‘Proved plus Probable’ and ‘Proved plus Probable plus Possible’ Reserve categories, at nominal discount rates of 7.5%, 10% and 12.5%, these being discount rates considered to be typical of those used in the petroleum industry for the appraisal of assets such as PY-3. GCA's assessment is based upon GCA’s understanding of the fiscal and contractual terms governing this asset. The values of physical assets, i.e. plant and equipment, have not been considered separately as such values have been implicitly included in the assessment of the NPVs as part of the petroleum property rights and facilities relating to the project. The NPVs of estimated after-tax cash flows (as at 31st December, 2010) attributable to a net economic interest in Hardy’s PY-3 Field, have been derived using the pricing and inflation assumptions as described herein. No adjustments have been made for cash balances, inventories, indebtedness or other balance sheet effects, other than those stated herein. It should be clearly understood that the NPV of future revenue potential of a petroleum property such as those discussed in this report, does not represent a GCA opinion as to the market value of that property, nor an interest in it. In assessing a likely market value, it may be necessary to take into account a number of additional factors including: Reserves risk (i.e. that Proved and/or Probable and/or Possible Reserves may not be realised within the anticipated timeframe for their exploitation); perceptions of economic and sovereign risk; potential upside, such as in this case exploitation of Reserves beyond the Proved and Probable and Possible level; other benefits, encumbrances or charges that may pertain to a particular interest and the competitive state of the market at the time. GCA has explicitly not taken such factors into account in deriving the NPVs presented herein. 2.1 Fiscal Systems The Production Sharing Contract pertaining to the PY-3 asset is summarised below: Cost Recovery Limit: 100.0% Profit Share Basis: Investment Multiple (IM), rates as shown below:

IM GOI Share (%) <1.5 10.0

1.5-2.0 25.0 2.0-2.5 40.0 2.5-3.0 55.0 3.0-3.5 60.0 >3.5 70.0

Investment Multiple (IM) is defined as the ratio of accumulated net cash income from the contract area to accumulated investment in the contract area, earned by the companies, as determined in the PSC. It is understood that the IM ratio cannot be adjusted downwards once a higher threshold has been reached. Hardy has advised that taxation of Hardy’s Indian assets is conducted at a Corporate rather than an asset/ contract level. However, in order to arrive at post-tax NPVs, GCA has assumed that the following Petroleum Income Tax and Minimum Alternative Tax rates are applicable. Hardy has advised that a carried forward loss of U.S.$24.6 MM is available to the company to offset future taxes payable on PY-3. This carried forward loss was included in the post-tax NPV analysis.

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Petroleum Income Tax: 42.23% Royalty: 0.0% Minimum Alternative Tax (MAT): 18.6%

2.2 Cost Assumptions GCA has based its assessment of forward capital and operating costs on the information provided by Hardy in the course of its audit. These have been benchmarked against GCA’s cost database for operations offshore India and found to be acceptable. 2.3 Oil Pricing The prices expected from the sale of crude oil produced from PY-3 were determined by applying a discount of U.S.$1/Bbl to Brent (based on 2010 realised prices) to reflect quality variation and location against the Brent marker prices below. GCA’s Brent price scenario for 1Q 2011 (used in this analysis) is presented below:

Year (U.S.$/Bbl) 2011 95.02 2012 94.82 2013 94.23 2014 94.72 2015 97.42 2016 99.37

Thereafter +2.0% p.a. Costs are inflated at 2.0% per annum from 1st January, 2012. 2.4 NPV Results The results of the economic analysis are presented in Table 2.1 below.

TABLE 2.1

PRE- AND POST-TAX NET PRESENT VALUES NET TO HARDY’S RESERVES AS AT 31st DECEMBER, 2010 (U.S.$ MM)

Asset Reserves Category

Pre-Tax NPV Post-Tax NPV

7.5% 10.0% 12.5% 7.5% 10.0% 12.5%

PY-3

Proved 12.29 12.02 11.77 12.29 12.02 11.77

Proved plus Probable 65.95 60.55 55.82 43.47 39.86 36.72

Proved plus Probable plus

Possible 97.89 88.59 80.54 57.72 51.79 46.69

Notes: 1. All cash flows are discounted on a mid-year basis to 31st December, 2010; 2. Post-Tax NPVs include a tax loss position as at 31st December, 2010 of U.S.$24.6 MM as advised by Hardy. 3. Pre-Tax NPVs are equivalent to Post-Tax NPVs for Proved Reserves due to tax losses carried forward from 31st

December, 2010.

Hardy 66 EE024430


3. QUALIFICATIONS

GCA is an independent international energy advisory group of over 50 years’ standing, whose expertise includes petroleum reservoir evaluation and economic analysis. The report is based on information compiled by professional staff members who are full time employees of GCA. Staff who participated in the compilation of this report includes Mr. Brian Rhodes, Dr M.I. Hussain, Mrs. Abby French, Mr. Michael Ring and Mr. Joel Chan. All hold degrees in geoscience, petroleum engineering or related discipline. Mr. Rhodes holds a B.Sc. (Hons) Geology, is a member of the Energy Institute, the Petroleum Exploration Society of Great Britain, the Society of Petroleum Engineers and the European Association of Geoscientists and Engineers, and has more than 35 years industry experience. Dr. Hussain is a senior reservoir engineer with 26 years industry experience. She has a Ph.D. and M.Sc in Petroleum Engineering and is a member of the Society of Petroleum Engineers and is a member of the Energy Institute. Mrs. French has a Masters degree and a diploma in Geochemistry, is a member of the Society of Petroleum Engineers and the Geological Society and has ten years experience in the industry. Mr. Ring holds a Bachelor of Science in Geology and a Masters of Arts in Geophysics; he is a member of the Society of Exploration Geophysicists and has over 34 years of industry experience. Mr. Chan is a senior economist with 13 years experience in economic analysis and valuations. He has a M.Soc.Sci. and B.Sc in Economics; he is a member of the Association of International Petroleum Negotiators and International Association for Energy Economics. 4. BASIS OF OPINION This assessment has been conducted within the context of GCA’s understanding of the effects of petroleum legislation, taxation, and other regulations that currently apply to these properties. However, GCA is not in a position to attest to property title, financial interest relationships or encumbrances thereon for any part of the appraised properties.

It should be understood that any determination of reserve volumes and corresponding NPVs, particularly involving petroleum developments, would be subject to significant variations over short periods of time as new information becomes available and perceptions change.

Yours sincerely, GAFFNEY, CLINE & ASSOCIATES LTD.

Brian Rhodes Principal Advisor

Gaffney, Cline & Associates

Hardy EE024430

APPENDIX I

Glossary

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GLOSSARY List of key abbreviations used in this report oAPI Degrees API (American Petroleum Institute) AVO Amplitude versus Offset AVA Amplitude versus offset Analysis B Billion (109) Bbl Barrels BCF Billion cubic feet BCM Billion cubic metres BRT Below rotary table bcpd Barrels of condensate per day BHP Bottom hole pressure bpd Barrels per day boe Barrels of oil equivalent @ xxx mcf/bbl bopd Barrels oil per day BS&W Basic sediment and water BTU British Thermal Units bwpd Barrels water per day CO2 Carbon Dioxide CAPEX Capital Expenditure cm centimetres CT Corporation Tax Deg C Degrees Celsius DHI Direct hydrocarbon indicator DST Drill Stem Test E&A Exploration & Appraisal EMV Expected Monetary Value EUR Estimated Ultimate Recovery ft3 Cubic feet Fx Foreign Exchange Rate G&A General and Administrative costs GIIP Gas initially in place GOR Gas Oil Ratio GOI Government of India H2S Hydrogen Sulphide HP High pressure HT High temperature kl Kilolitres km Kilometers km2 Square kilometres LNG Liquefied Natural Gas LoF Life of Field LPG Liquefied Petroleum Gas m Metres m3 Cubic metres mD Permeability in millidarcies mg Milligram M Thousand MM Million ms milliseconds mya Million years ago NGL Natural Gas Liquids N Nitrogen

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GLOSSARY (Cont'd.) NELP New Exploration Licensing Policy NPV Net Present Value NWI Net Working Interest/Net Participating Interest OCM Operating Committee Meeting OPEX Operating Expenditure p.a. Per annum ppm Part per million psi Pounds per square inch psig Pounds per square inch gauge PVT Pressure volume temperature PDHG Downhole pressure gauge RFT Repeat Formation Tester scf Standard Cubic Feet scfd Standard Cubic Feet per day SL Straight line (for depreciation) SS Subsea stb Stock tank barrel STOIIP Stock tank oil initially in place T Trillion (1012) TCF Trillion cubic feet Te Tonnes equivalent TCM Technical Committee Meeting THP Tubing head pressure TOC Total Organic Carbon Tpd Tonnes per day TVDSS True Vertical Depth Subsea WD Water depth WI Working Interest 2D Two dimensional 3D Three dimensional % Percentage U.S.$ United States Dollar

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APPENDIX II

Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers, Petroleum Resources

Management System Definitions and Guidelines

Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers

Petroleum Resources Management System

Definitions and Guidelines (1)

March 2007

Preamble Petroleum resources are the estimated quantities of hydrocarbons naturally occurring on or within the Earth’s crust. Resource assessments estimate total quantities in known and yet-to-be-discovered accumulations; resources evaluations are focused on those quantities that can potentially be recovered and marketed by commercial projects. A petroleum resources management system provides a consistent approach to estimating petroleum quantities, evaluating development projects, and presenting results within a comprehensive classification framework. International efforts to standardize the definition of petroleum resources and how they are estimated began in the 1930s. Early guidance focused on Proved Reserves. Building on work initiated by the Society of Petroleum Evaluation Engineers (SPEE), SPE published definitions for all Reserves categories in 1987. In the same year, the World Petroleum Council (WPC, then known as the World Petroleum Congress), working independently, published Reserves definitions that were strikingly similar. In 1997, the two organizations jointly released a single set of definitions for Reserves that could be used worldwide. In 2000, the American Association of Petroleum Geologists (AAPG), SPE and WPC jointly developed a classification system for all petroleum resources. This was followed by additional supporting documents: supplemental application evaluation guidelines (2001) and a glossary of terms utilized in Resources definitions (2005). SPE also published standards for estimating and auditing reserves information (revised 2007). These definitions and the related classification system are now in common use internationally within the petroleum industry. They provide a measure of comparability and reduce the subjective nature of resources estimation. However, the technologies employed in petroleum exploration, development, production and processing continue to evolve and improve. The SPE Oil and Gas Reserves Committee works closely with other organizations to maintain the definitions and issues periodic revisions to keep current with evolving technologies and changing commercial opportunities. The SPE PRMS document consolidates, builds on, and replaces guidance previously contained in the 1997 Petroleum Reserves Definitions, the 2000 Petroleum Resources Classification and Definitions publications, and the 2001 “Guidelines for the Evaluation of Petroleum Reserves and Resources”; the latter document remains a valuable source of more detailed background information., These definitions and guidelines are designed to provide a common reference for the international petroleum industry, including national reporting and regulatory disclosure agencies, and to support petroleum project and portfolio management requirements. They are intended to improve clarity in global communications regarding petroleum resources. It is expected that SPE PRMS will be supplemented with industry education programs and application guides addressing their implementation in a wide spectrum of technical and/or commercial settings. It is understood that these definitions and guidelines allow flexibility for users and agencies to tailor application for their particular needs; however, any modifications to the guidance contained herein should be clearly identified. The definitions and guidelines contained in this document must not be construed as modifying the interpretation or application of any existing regulatory reporting requirements. The full text of the SPE PRMS Definitions and Guidelines can be viewed at: www.spe.org/specma/binary/files/6859916Petroleum_Resources_Management_System_2007.pdf

1 These Definitions and Guidelines are extracted from the Society of Petroleum Engineers / World Petroleum Council /

American Association of Petroleum Geologists / Society of Petroleum Evaluation Engineers (SPE/WPC/AAPG/SPEE) Petroleum Resources Management System document (“SPE PRMS”), approved in March 2007.

RESERVES

Reserves are those quantities of petroleum anticipated to be commercially recoverable by application of development projects to known accumulations from a given date forward under defined conditions.

Reserves must satisfy four criteria: they must be discovered, recoverable, commercial, and remaining based on the development project(s) applied. Reserves are further subdivided in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their development and production status. To be included in the Reserves class, a project must be sufficiently defined to establish its commercial viability. There must be a reasonable expectation that all required internal and external approvals will be forthcoming, and there is evidence of firm intention to proceed with development within a reasonable time frame. A reasonable time frame for the initiation of development depends on the specific circumstances and varies according to the scope of the project. While 5 years is recommended as a benchmark, a longer time frame could be applied where, for example, development of economic projects are deferred at the option of the producer for, among other things, market-related reasons, or to meet contractual or strategic objectives. In all cases, the justification for classification as Reserves should be clearly documented. To be included in the Reserves class, there must be a high confidence in the commercial producibility of the reservoir as supported by actual production or formation tests. In certain cases, Reserves may be assigned on the basis of well logs and/or core analysis that indicate that the subject reservoir is hydrocarbon-bearing and is analogous to reservoirs in the same area that are producing or have demonstrated the ability to produce on formation tests.

On Production

The development project is currently producing and selling petroleum to market.

The key criterion is that the project is receiving income from sales, rather than the approved development project necessarily being complete. This is the point at which the project “chance of commerciality” can be said to be 100%. The project “decision gate” is the decision to initiate commercial production from the project.

Approved for Development

A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.

At this point, it must be certain that the development project is going ahead. The project must not be subject to any contingencies such as outstanding regulatory approvals or sales contracts. Forecast capital expenditures should be included in the reporting entity’s current or following year’s approved budget. The project “decision gate” is the decision to start investing capital in the construction of production facilities and/or drilling development wells.

Justified for Development

Implementation of the development project is justified on the basis of reasonable forecast commercial conditions at the time of reporting, and there are reasonable expectations that all necessary approvals/contracts will be obtained.

In order to move to this level of project maturity, and hence have reserves associated with it, the development project must be commercially viable at the time of reporting, based on the reporting entity’s assumptions of future prices, costs, etc. (“forecast case”) and the specific circumstances of the project. Evidence of a firm intention to proceed with development within a reasonable time frame will be sufficient to demonstrate commerciality. There should be a development plan in sufficient detail to support the assessment of commerciality and a reasonable expectation that any regulatory approvals or sales contracts required prior to project implementation will be forthcoming. Other than such approvals/contracts, there should be no known contingencies that could preclude the development from proceeding within a reasonable timeframe (see Reserves class). The project “decision gate” is the decision by the reporting entity and its partners, if any, that the project has reached a level of technical and commercial maturity sufficient to justify proceeding with development at that point in time.

Proved Reserves

Proved Reserves are those quantities of petroleum, which by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be commercially recoverable, from a given date forward, from known reservoirs and under defined economic conditions, operating methods, and government regulations.

If deterministic methods are used, the term reasonable certainty is intended to express a high degree of confidence that the quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities actually recovered will equal or exceed the estimate. The area of the reservoir considered as Proved includes:

(1) the area delineated by drilling and defined by fluid contacts, if any, and

(2) adjacent undrilled portions of the reservoir that can reasonably be judged as continuous with it and commercially productive on the basis of available geoscience and engineering data.

In the absence of data on fluid contacts, Proved quantities in a reservoir are limited by the lowest known hydrocarbon (LKH) as seen in a well penetration unless otherwise indicated by definitive geoscience, engineering, or performance data. Such definitive information may include pressure gradient analysis and seismic indicators. Seismic data alone may not be sufficient to define fluid contacts for Proved reserves (see “2001 Supplemental Guidelines,” Chapter 8). Reserves in undeveloped locations may be classified as Proved provided that the locations are in undrilled areas of the reservoir that can be judged with reasonable certainty to be commercially productive. Interpretations of available geoscience and engineering data indicate with reasonable certainty that the objective formation is laterally continuous with drilled Proved locations. For Proved Reserves, the recovery efficiency applied to these reservoirs should be defined based on a range of possibilities supported by analogs and sound engineering judgment considering the characteristics of the Proved area and the applied development program.

Probable Reserves

Probable Reserves are those additional Reserves which analysis of geoscience and engineering data indicate are less likely to be recovered than Proved Reserves but more certain to be recovered than Possible Reserves.

It is equally likely that actual remaining quantities recovered will be greater than or less than the sum of the estimated Proved plus Probable Reserves (2P). In this context, when probabilistic methods are used, there should be at least a 50% probability that the actual quantities recovered will equal or exceed the 2P estimate. Probable Reserves may be assigned to areas of a reservoir adjacent to Proved where data control or interpretations of available data are less certain. The interpreted reservoir continuity may not meet the reasonable certainty criteria. Probable estimates also include incremental recoveries associated with project recovery efficiencies beyond that assumed for Proved.

Possible Reserves

Possible Reserves are those additional reserves which analysis of geoscience and engineering data indicate are less likely to be recoverable than Probable Reserves

The total quantities ultimately recovered from the project have a low probability to exceed the sum of Proved plus Probable plus Possible (3P), which is equivalent to the high estimate scenario. When probabilistic methods are used, there should be at least a 10% probability that the actual quantities recovered will equal or exceed the 3P estimate. Possible Reserves may be assigned to areas of a reservoir adjacent to Probable where data control and interpretations of available data are progressively less certain. Frequently, this may be in areas where geoscience and engineering data are unable to clearly define the area and vertical reservoir limits of commercial production from the reservoir by a defined project. Possible estimates also include incremental quantities associated with project recovery efficiencies beyond that assumed for Probable.

Probable and Possible Reserves

(See above for separate criteria for Probable Reserves and Possible Reserves.)

The 2P and 3P estimates may be based on reasonable alternative technical and commercial interpretations within the reservoir and/or subject project that are clearly documented, including comparisons to results in successful similar projects. In conventional accumulations, Probable and/or Possible Reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a reservoir within the same accumulation that may be separated from Proved areas by minor faulting or other geological discontinuities and have not been penetrated by a wellbore but are interpreted to be in communication with the

known (Proved) reservoir. Probable or Possible Reserves may be assigned to areas that are structurally higher than the Proved area. Possible (and in some cases, Probable) Reserves may be assigned to areas that are structurally lower than the adjacent Proved or 2P area. Caution should be exercised in assigning Reserves to adjacent reservoirs isolated by major, potentially sealing, faults until this reservoir is penetrated and evaluated as commercially productive. Justification for assigning Reserves in such cases should be clearly documented. Reserves should not be assigned to areas that are clearly separated from a known accumulation by non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results); such areas may contain Prospective Resources. In conventional accumulations, where drilling has defined a highest known oil (HKO) elevation and there exists the potential for an associated gas cap, Proved oil Reserves should only be assigned in the structurally higher portions of the reservoir if there is reasonable certainty that such portions are initially above bubble point pressure based on documented engineering analyses. Reservoir portions that do not meet this certainty may be assigned as Probable and Possible oil and/or gas based on reservoir fluid properties and pressure gradient interpretations.

Developed Reserves Developed Reserves are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed, or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify Developed Reserves as Undeveloped. Developed Reserves may be further sub-classified as Producing or Non-Producing.

Developed Producing Reserves Developed Producing Reserves are expected to be recovered from completion intervals that are open and producing at the time of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing Reserves

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves

Shut-in Reserves are expected to be recovered from:

(1) completion intervals which are open at the time of the estimate but which have not yet started producing,

(2) wells which were shut-in for market conditions or pipeline connections, or

(3) wells not capable of production for mechanical reasons.

Behind-pipe Reserves are expected to be recovered from zones in existing wells which will require additional completion work or future re-completion prior to start of production. In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

Undeveloped Reserves

Undeveloped Reserves are quantities expected to be recovered through future investments:

(1) from new wells on undrilled acreage in known accumulations,

(2) from deepening existing wells to a different (but known) reservoir,

(3) from infill wells that will increase recovery, or

(4) where a relatively large expenditure (e.g. when compared to the cost of drilling a new well) is required to

(a) recomplete an existing well or

(b) install production or transportation facilities for primary or improved recovery projects.

CONTINGENT RESOURCES

Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations by application of development projects, but which are not currently considered to be commercially recoverable due to one or more contingencies.

Contingent Resources may include, for example, projects for which there are currently no viable markets, or where commercial recovery is dependent on technology under development, or where evaluation of the accumulation is insufficient to clearly assess commerciality. Contingent Resources are further categorized in accordance with the level of certainty associated with the estimates and may be sub-classified based on project maturity and/or characterized by their economic status.

Development Pending

A discovered accumulation where project activities are ongoing to justify commercial development in the foreseeable future.

The project is seen to have reasonable potential for eventual commercial development, to the extent that further data acquisition (e.g. drilling, seismic data) and/or evaluations are currently ongoing with a view to confirming that the project is commercially viable and providing the basis for selection of an appropriate development plan. The critical contingencies have been identified and are reasonably expected to be resolved within a reasonable time frame. Note that disappointing appraisal/evaluation results could lead to a re-classification of the project to “On Hold” or “Not Viable” status. The project “decision gate” is the decision to undertake further data acquisition and/or studies designed to move the project to a level of technical and commercial maturity at which a decision can be made to proceed with development and production.

Development Unclarified or on Hold

A discovered accumulation where project activities are on hold and/or where justification as a commercial development may be subject to significant delay.

The project is seen to have potential for eventual commercial development, but further appraisal/evaluation activities are on hold pending the removal of significant contingencies external to the project, or substantial further appraisal/evaluation activities are required to clarify the potential for eventual commercial development. Development may be subject to a significant time delay. Note that a change in circumstances, such that there is no longer a reasonable expectation that a critical contingency can be removed in the foreseeable future, for example, could lead to a reclassification of the project to “Not Viable” status. The project “decision gate” is the decision to either proceed with additional evaluation designed to clarify the potential for eventual commercial development or to temporarily suspend or delay further activities pending resolution of external contingencies.

Development Not Viable

A discovered accumulation for which there are no current plans to develop or to acquire additional data at the time due to limited production potential.

The project is not seen to have potential for eventual commercial development at the time of reporting, but the theoretically recoverable quantities are recorded so that the potential opportunity will be recognized in the event of a major change in technology or commercial conditions. The project “decision gate” is the decision not to undertake any further data acquisition or studies on the project for the foreseeable future.

PROSPECTIVE RESOURCES Those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations. Potential accumulations are evaluated according to their chance of discovery and, assuming a discovery, the estimated quantities that would be recoverable under defined development projects. It is recognized that the development programs will be of significantly less detail and depend more heavily on analog developments in the earlier phases of exploration. Prospect

A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target. Project activities are focused on assessing the chance of discovery and, assuming discovery, the range of potential recoverable quantities under a commercial development program. Lead A project associated with a potential accumulation that is currently poorly defined and requires more data acquisition and/or evaluation in order to be classified as a prospect. Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to confirm whether or not the lead can be matured into a prospect. Such evaluation includes the assessment of the chance of discovery and, assuming discovery, the range of potential recovery under feasible development scenarios. Play A project associated with a prospective trend of potential prospects, but which requires more data acquisition and/or evaluation in order to define specific leads or prospects. Project activities are focused on acquiring additional data and/or undertaking further evaluation designed to define specific leads or prospects for more detailed analysis of their chance of discovery and, assuming discovery, the range of potential recovery under hypothetical development scenarios.

RESOURCES CLASSIFICATION

PROJECT MATURITY

gca gaffney, cline & associatesfiles.investis.com/hardyoil/reports/irp2011/cpr_2011.pdfemail:...

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