Introduction to the Official List Arden Partners

This document comprises a prospectus relating to Hardy Oil and Gas plc prepared in accordance with the Prospectus Rules of the UK Listing Authority made under section 73A of the Financial Services and Markets Act 2000. Application has been made to the UK Listing Authority and to the London Stock Exchange respectively for admission of all of the Ordinary Shares to: (i) the Official List; and (ii) the London Stock Exchange’s market for listed securities. No application has been made or is currently intended to be made for the Ordinary Shares to be admitted to listing or dealt with on any other exchange. It is expected that Admission will become effective and that dealings on the London Stock Exchange in the Ordinary Shares will commence on 20 February 2008 (International Security Identification Number: GB00B09MB366). Upon Admission, the admission of the Company’s Ordinary Shares to trading on AIM will be cancelled. This document has not been, and does not need to be, approved by the Isle of Man Financial Supervision Commission, or any governmental or regulatory authority in or of the Isle of Man. The Ordinary Shares have not been, and will not be, registered under the US Securities Act or under the securities laws of any state, district or other jurisdiction of the United States, or of Canada, Japan or Australia, or any other jurisdiction and no regulatory clearances in respect of the Ordinary Shares have been, or will be, applied for in any jurisdiction other than the UK. Prospective investors should read the entire document and, in particular, the risk factors set out in the section entitled ‘‘Risk Factors’’ when considering an investment in the Company.

(Incorporated and registered in the Isle of Man with registered no. 87462C)

INTRODUCTION TO THE OFFICIAL LIST

Sponsor and Broker ARDEN PARTNERS PLC

Arden Partners Plc, which is authorised and regulated in the United Kingdom by the FSA, is acting only for Hardy Oil and Gas plc and no-one else in connection with Admission and will not regard any other person as its client or be responsible to any person other than Hardy Oil and Gas plc for providing the protections afforded to its clients or for advising any other person on the contents of this document. Investors should rely only on the information in this document. No person has been authorised to give any information or make any representations other than those contained in this document and, if given or made, such information or representations must not be relied on as having been authorised by the Company. Without prejudice to any obligation of the Company to publish a supplementary prospectus pursuant to section 87G of FSMA or paragraph 3.4 of the Prospectus Rules, the publication of this document does not, under any circumstances, create any implication that there has been no change in the affairs of the Group since, or that the information contained herein is correct at any time subsequent to, the date of this document. The contents of this document are not to be construed as legal, business or tax advice. Each prospective investor should consult his, her or its own solicitor, independent financial adviser or tax adviser for legal, financial or tax advice. CONTENTS

Page SUMMARY ...... 3 RISK FACTORS ...... 7 DIRECTORS, SECRETARY AND ADVISERS ...... 16 PART 1 — INTRODUCTION TO HARDY OIL AND GAS PLC ...... 18 PART 2 — MANAGEMENT ...... 39 PART 3 — COMPETENT PERSON’S REPORT ...... 42 PART 4 — OPERATING AND FINANCIAL REVIEW ...... 119 PART 5 — FINANCIAL INFORMATION ...... 126 SECTION A — FINANCIAL INFORMATION ON HARDY (IFRS — PERIOD ENDED 126 30 SEPTEMBER 2007) ...... SECTION B — FINANCIAL INFORMATION ON HARDY (IFRS — 2005 AND 2006) ...... 148 SECTION C — FINANCIAL INFORMATION ON HARDY (UK GAAP — 2004 AND 2005) . 179 SECTION D — CAPITALISATION AND INDEBTEDNESS STATEMENT...... 198 PART 6 — ADDITIONAL INFORMATION ...... 199 PART 7 — DEFINITIONS AND GLOSSARY ...... 222

2 SUMMARY

The following summary information does not purport to be complete and should be read as an introduction to the more detailed information appearing elsewhere in this document. Any decision by a prospective investor to invest in Ordinary Shares should be based on consideration of the document as a whole and not solely on this summarised information. Following the implementation of the relevant provisions of the Prospectus Directive in each member state of the European Economic Area, civil liability will attach to the persons who are responsible for this summary, including any translation thereof, in such member state but only if the summary is misleading, inaccurate or inconsistent when read together with the other parts of this document. Where a claim relating to the information contained in this document is brought before a court in a member state of the European Economic Area, the claimant may, under the national legislation of that member state where the claim is brought, be required to bear the costs of translating this document before the legal proceedings are initiated.

Overview Hardy Oil and Gas plc is an international oil and gas exploration and production company primarily focused on India and with some development interests in Nigeria. The Group has assembled an attractive portfolio of exploration, development and production assets.

Company history The Company was originally incorporated under the name Jehan Energy Limited in 1997 by the founders, Messrs Sastry Karra and Yogeshwar Sharma, with the purpose of developing an oil and gas exploration and production business in India that built on the expertise and relationships of the management team. Management also aimed to exploit the substantial increase in demand for energy in India which followed liberalisation measures initiated by the Government of India in 1991, principally privatisation and the opening up of the economy to foreign companies, and the subsequent increase in economic activity. Through asset acquisition, reserve optimisation and the development of strong working relationships, the Group has assembled a strategic position in the oil and gas basins on the east coast of India, and off the Saurashtra west coast near the Bombay High field. The Company has also acquired development assets in the Niger Delta of Nigeria, a proven oil province. In September 1999 the Company acquired HEPI from a subsidiary of British-Borneo Oil & Gas plc. In 2001, the Company purchased an 8.5 per cent. shareholding in HOEC. The Company was subsequently renamed Hardy Oil and Gas Limited in 2001 and converted to a public limited company on 31 May 2005. On 7 June 2005, the Ordinary Shares were admitted to trading on the AIM market of the London Stock Exchange at a price per Ordinary Share of 144p. On 5 August 2005 the Company announced that, through the India NELP-V round, it had been awarded the KG-DWN-2003/1 deepwater exploration licence (‘‘D3’’). HEPI had jointly bid for this licence with Reliance. On 21 March 2006 the Company announced the acquisition of two licences in the Niger Delta of Nigeria, Oza and Atala. The Company acquired the interests via separate farm-in agreements entitling the company to a 40 per cent. working interest of the Oza field and a 20 per cent. working interest of the Atala field, subject to various terms and conditions. On 8 January 2007 the Company announced a discovery in the Fan A-1 well, located in the Hardy operated CY-OS/2 licence. On 15 May 2007 the Company announced the discovery of hydrocarbons in the Reliance operated B-1 well located on the Company’s GS-01 licence. Further drilling on this licence is expected in 2008. On 10 August 2007 the Company announced the agreed appraisal programme of drilling three additional wells in the CY-OS/2 licence. On 31 December 2007 the Company announced that a well test was successfully carried out on well no. 4 in the Oza field in Nigeria, with flow rates averaging approximately 600 stbd of oil and average GOR of 5,466 scf/stb.

3 On 13 February 2008, the Company announced a gas discovery (Dhirubhai 39) in the Reliance operated KGV-D3-A1 well located on the Company’s D3 licence. The Company also announced the spudding of a second well (KGV-D3-B1) to evaluate Pleistocene and Late to Mid Miocene sandstone reservoirs. The well is expected to reach a TD of 2,740 m.

SUMMARY OF INTERESTS GCA, an independent petroleum engineering consultancy, was commissioned to prepare estimates of the proved, probable, and possible oil, condensate, and sales gas reserves and the contingent and prospective resources contained within the Group’s assets. The Group has Proved Reserves (net) and Probable Reserves (net) of 2.69 MMbbl and best estimate net Contingent Resources of 80.9 Bcf of gas and 21.0 MMbbl of oil. Further, the Group has a portfolio of Prospective Resources in a number of exploration permits. Full details of the reserves and resources are given on pages 20-23 of this document and in GCA’s report (part 3). The Group has interests in a number of assets in India and Nigeria that comprise production, potential development, discoveries and exploration. The Indian assets are held through HEPI, a wholly owned subsidiary. The pertinent net participating interest (‘‘NPI’’) 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 (HEPI NPI 18 per cent.); • Block CY-OS/2, located in the Cauvery Basin, offshore Tamil Nadu (HEPI NPI 75 per cent.); • Block GS-01 (NELP II), located in the Bombay offshore Basin, to the West and Northwest of the ONGC operated Bombay High field (HEPI NPI 10 per cent.); • Block D9 (NELP III) in the offshore Krishna-Godavari Basin (HEPI NPI 10 per cent.), located immediately to the east of Reliance’s 2003 gas discoveries in Block KG-DWN-98/3; and • Block D3 (NELP V), in the offshore Krishna-Godavari Basin due west and some 50 km inshore of the Reliance concession mentioned above (HEPI NPI 10 per cent.). The Nigerian assets are held through HON, a wholly owned subsidiary. Both blocks are onshore in the Niger delta basin and the pertinent net working interest (‘‘NWI’’) fractions are comprised of the following: • Oza Field concession area, a formerly producing oilfield (HON NWI 40 per cent.) located in Oil Mining Licence (OML) 11 in Rivers State, and 33 km northeast of the city of Port Harcourt; and • Atala concession area (HON NWI 20 per cent.), located in OML 46 in Bayelsa State in the Coastal Swamp Depobelt less than 10 km from the coast.

CURRENT TRADING AND FUTURE PROSPECTS In 2007, the Group announced discoveries on two of its four exploration licences in India. Hardy’s management team is fully focused on implementing the HEPI operated CY-OS/2 appraisal and PY-3 development drilling programmes comprising five wells. It is expected that the implementation of the CY-OS/2 appraisal drilling programme, and PY-3 phase III development programme, will dominate Hardy’s focus throughout 2008. The Group expects to maintain the current PY-3 field gross daily production level of 3,200 stb/d through the remainder of 2008. The Board is considering farming out a portion of its participating interest in CY-OS/2. In addition, the Board envisages that during 2008 the Group’s exploration programme will accelerate and the Board expects to drill on all three of HEPI’s non-operated exploration licences in India. Hardy will also continue to assess investment opportunities that will complement the Group’s asset portfolio. The Group’s main focus remains in India where it has assembled its exploration and production team. Hardy is looking forward to a number of specific initiatives for 2008: • D3 – evaluating the results of the first successful well and the second follow up well, processing seismic and shooting additional seismic on the block;

4 • GS-01 — initiating acquisition of an additional 1,000 km2 of 3D seismic in the first quarter of 2008 and commence drilling of three additional wells in the second quarter of 2008; • D9 – spudding of the first well during the latter half of 2008 at the earliest. Other activity will be subject to various approvals and availability: • PY-3 phase III — subject to rig availability, begin the phase III development plan with the drilling of one development well and a water injection well to extend the field life, and potentially add recoverable reserves; • CY-OS/2 — subject to securing an appropriate offshore drilling rig, HEPI may commence appraisal drilling in the last quarter of 2008; • Oza — subject to agreement with third-parties and government approvals, HON may initiate the first phase development programme with installation of pipeline and production facilities. It is thought that sustainable production may begin by the second quarter of 2009.

Summary of financial information The table below provides selected financial information in relation to the Group. Selected financial information has been extracted without material adjustment from Section A in ‘‘Financial Information’’ in Part 5 of this document. Investors should read the whole of this document and not rely solely on key or summarised information. 1 January to Year ended 30 September 31 December 2007 2006 US$ US$ Revenue 11,719,108 21,316,935 Profit on ordinary activities before taxation 4,035,857 9,025,374 Net assets at end of period 138,956,623 91,401,836 Cash and cash equivalents at end of period 33,424,168 24,990,939

RISK FACTORS The attention of prospective investors is drawn to the fact that ownership of Ordinary Shares in the Company will involve a variety of risks. • There are risks inherent in the exploration, exploitation, appraisal, development and production of oil and gas reserves and resources. • The Group cannot guarantee that it will be able to identify appropriate properties or negotiate acquisitions on favourable terms or that it will be able to obtain the financing necessary to complete such future acquisitions. • Estimating the quantity of reserves and resources and projecting future rates of production is a subjective process and has inherent uncertainties. • Many of the assumptions used in estimating reserves are beyond the Group’s control and may prove to be incorrect over time. • Appraisal results for discoveries are uncertain. Appraisal and development activities involving the drilling of wells across a field may be unpredictable and not result in the outcome planned, targeted or predicted, as only by extensive testing can the properties of the entire field be fully understood. • The Group’s production operations involve risks common to its industry. • The Group’s drilling activities may be unsuccessful and the actual costs incurred in drilling, operating wells and completing well workovers may exceed budget. • The Group’s drilling activities may be unsuccessful and the actual costs incurred in drilling, operating wells and completing well workovers may exceed budget.

5 • The Group undertakes exploration activities and incurs significant costs with no guarantee that such expenditures will result in the discovery of commercially deliverable oil or gas. • Each of the Group’s India exploration licences and Nigerian assets requires minimum work programmes to be fulfilled. Failure to comply with such obligations, may lead to fines, penalties, restrictions and withdrawal of licences with consequent material adverse effects. • The Group may suffer from delays or interruptions due to lack of availability of drilling rigs or construction of infrastructure, the failure of a third party provider or supplier of equipment or services could have a material adverse impact on the Group’s business and the results of its operations. • The Group operates in areas with extreme and seasonal weather conditions. • The Group’s business necessarily involves significant capital expenditure. • The Group requires a significant amount of cash in order to fund its anticipated exploration, appraisal and development work programme to maintain its operations to pursue its strategy of growth by acquisitions of additional fields and assets, and meet its liquidity needs. • Where the Group acquires another company or its assets, and integrates operations and personnel, the pre or post-completion costs may render the value of any company or assets acquired to be less than the amount paid. • The Group may suffer material losses from uninsurable or insured risks or insufficient insurance coverage. The Group is exposed to foreign exchange risk. • Historically, oil prices have fluctuated widely and are affected by numerous factors over which the Group has no control. • The oil and gas industry is highly competitive. • From time to time, the Group may be subject to litigation arising out of its operations. • There are numerous factors which may affect the success of the Group’s business which are beyond the Group’s control. • Failure to successfully manage the Group’s expected growth and development could have a material adverse effect on the Group. • Demand for limited equipment such as drilling rigs or access restrictions may affect the availability of such equipment to the Group and may delay its development and exploration activities. • The Group’s principal current assets and operations are located in India where there may be risks over which it will have no, or limited, control. • There are political, economic and other risks relating to Nigeria or to other countries in which it may operate in the future. • Exploitation of discovered oil and gas deposits will involve the need to obtain licence or clearance from the relevant governmental authorities. • The Group is subject to extensive government laws and regulations. • The Group’s operations are, and will be, subject to environmental regulation. Compliance with environmental regulations could increase the Group’s costs. • The Group relies significantly on strategic relationships with other entities. • There can be no guarantee that the Group will be able to continue to attract and retain required employees. • Share prices may fluctuate from time to time for various reasons. The value of the Ordinary Shares and the can go down as well as up.

6 RISK FACTORS

THE ATTENTION OF PROSPECTIVE INVESTORS IS DRAWN TO THE FACT THAT OWNERSHIP OF SHARES IN THE COMPANY WILL INVOLVE A VARIETY OF RISKS WHICH, IF THEY OCCUR, MAY HAVE A MATERIALLY ADVERSE EFFECT ON THE GROUP’S BUSINESS OR FINANCIAL CONDITION, RESULTS OR FUTURE OPERATIONS. IN SUCH CASE, THE MARKET PRICE OF THE ORDINARY SHARES COULD DECLINE AND AN INVESTOR MIGHT LOSE ALL OR PART OF HIS OR HER INVESTMENT. IN ADDITION TO THE INFORMATION SET OUT IN THIS DOCUMENT, THE FOLLOWING RISK FACTORS SHOULD BE CONSIDERED CAREFULLY IN EVALUATING WHETHER TO MAKE AN INVESTMENT IN THE COMPANY. THE FOLLOWING FACTORS ARE NOT SET OUT IN ANY ORDER OF PRIORITY. IN PARTICULAR, THE COMPANY’S PERFORMANCE MIGHT BE AFFECTED BY CHANGES IN MARKET AND/OR ECONOMIC CONDITIONS AND IN LEGAL, REGULATORY AND TAX REQUIREMENTS. ADDITIONALLY, THERE MAY BE RISKS OF WHICH THE BOARD IS NOT AWARE OR BELIEVES TO BE IMMATERIAL WHICH MAY, IN THE FUTURE, ADVERSELY AFFECT THE GROUP’S BUSINESS AND THE MARKET PRICE OF THE ORDINARY SHARES. BEFORE MAKING A FINAL INVESTMENT DECISION, PROSPECTIVE INVESTORS SHOULD CONSIDER CAREFULLY WHETHER AN INVESTMENT IN THE COMPANY IS SUITABLE FOR THEM AND, IF THEY ARE IN ANY DOUBT, SHOULD CONSULT WITH AN INDEPENDENT FINANCIAL ADVISER AUTHORISED UNDER THE FINANCIAL SERVICES AND MARKETS ACT 2000 WHO SPECIALISES IN ADVISING ON THE ACQUISITION OF SHARES AND OTHER SECURITIES IN THE UK. GENERAL EXPLORATION, DEVELOPMENT AND PRODUCTION RISKS The Group’s strategy is predominantly driven by the exploration, exploitation, appraisal, development and production of its existing assets. There are risks inherent in the exploration, exploitation, appraisal, development and production of oil and gas reserves and resources. Whilst the rewards can be substantial, there is no guarantee that exploration will lead to further commercial discoveries. Exploration and production activities by their nature involve significant risks. Risks such as delays in the construction and commissioning of drilling platforms or other technical difficulties, lack of access to key infrastructure, adverse weather conditions, environmental hazards, industrial accidents, occupational and health hazards, technical failures, labour disputes, unusual or unexpected geological formations, explosions and other acts of God are inherent to the business. Although in many cases these represent insurable risks, the Group may also become subject to other hazards (including pollution and oil seepage liability) against which it is not insured or is under insured. The occurrence of any of these incidents can result in the Group’s current or future project target dates for drilling or production being delayed or interrupted, increased capital expenditure and production costs and result in liability to the Contractor or Operator of the field. The Group’s strategy depends partly on its ability to make additional acquisitions of oil and gas exploration and production rights. The Group cannot guarantee that it will be able to identify appropriate properties or negotiate acquisitions on favourable terms or that it will be able to obtain the financing necessary to complete such future acquisitions. If the Group is unable to acquire additional oil and gas rights on properties, it cannot be certain that it will be able to expand or replace its current exploration portfolio nor add production with new reserves. The Group’s current business is dependent on the continuing enforceability of the PSCs, farm-in agreements and exploration and development licences summarised in this document. BUSINESS RISK Oil and gas reserves or resources Unless stated otherwise, the oil and gas reserves and resources data contained herein are extracted from a report by GCA. These reserves and resource estimates have been prepared in accordance with the definitions of the SPE, the WPC, the AAPG and the SPEE, March 2007. The reserves and resources data contained in this document have been estimated by GCA unless stated otherwise. Estimating the quantity of reserves and resources and projecting future rates of production is a subjective process and has inherent uncertainties, including factors beyond Hardy’s control.

7 The estimates of reserves and resources data contained should not be construed as exact. Reserves estimates contained in this document are based on production, prices, costs, ownership, geophysical, geological and engineering data and other information collated by Hardy. The estimates may prove to be incorrect after further drilling, testing and production. Forward-looking statements contained herein (including data included in the report by GCA or taken from the report by GCA and whether expressed to have been estimated by GCA or otherwise) concerning the Group’s reserves and resources definitions should not be unduly relied upon by potential investors. Certain categories of reserves and resources (such as Prospective and Contingent Resources) are inherently riskier than certain other categories (such as Proved Reserves). If the assumptions upon which the estimates of Hardy’s oil and gas reserves or resources are based prove to be incorrect, Hardy may be unable to recover and produce the estimated levels or quality of oil or gas set out in this document and Hardy’s business, prospects and financial results could be materially and adversely affected. Assumptions underlying reserve and resource estimates Estimation of underground accumulations of oil or gas is a subjective process aimed at understanding the statistical probabilities of recovery. Estimates of the quantity of economically recoverable oil or gas reserves, rates of production, net present value of future cash flows and the timing of development expenditures depend upon several variables and assumptions, including the following: • production history compared with production from other comparable producing areas; • interpretation of geological and geophysical data; • effects of regulations adopted by governmental agencies; • future oil and gas prices; • capital expenditure; and • future operating costs, royalties, tax on the extraction of commercial minerals, development costs and workover and remedial costs. Considering that all reserve estimates are subjective, each of the following items may differ materially from those assumed in estimating reserves: • the quantities and qualities that are ultimately recovered; • the production and operating costs incurred; • the amount and timing of additional exploration and future development expenditures; and • future oil and gas sales prices. Many of the assumptions used in estimating reserves are beyond the Group’s control and may prove to be incorrect over time. Evaluations of reserves necessarily involve multiple uncertainties. The accuracy of any reserves or resources evaluation depends on the quality of available information, petroleum engineering and geological interpretation. Exploration drilling, interpretation, testing and production after the date of the estimates may require substantial upward or downward revisions in Hardy’s reserves or resources data. Moreover, different reservoir engineers may make varying estimates of reserves and cash flows based on the same available data. Actual production, revenues and expenditures with respect to reserves and resources will vary from estimates, and the variances may be material. Uncertainties exist with respect to the estimation of resources in addition to those set forth above that apply to reserves. The probability that Prospective Resources will be discovered, or be economically recoverable, is considerably lower than for Proven, Probable and Possible Reserves. Volumes associated with Prospective Resources should be considered highly speculative. Appraisal and development Appraisal results for discoveries are also uncertain. Appraisal and development activities involving the drilling of wells across a field may be unpredictable and not result in the outcome planned, targeted or predicted, as only by extensive testing can the properties of the entire field be fully understood. Production The Group’s production operations involve risks common to its industry, including blowouts, oil spills, explosions, fires, equipment damage or failure, natural disasters, geological uncertainties, early water

8 breakthrough, unusual or unexpected rock formations and abnormal geological pressures. In the event that any of these occur, environmental damage, injury to persons and loss of life, failure to produce oil or gas in commercial quantities or an inability to fully produce discovered reserves could result. They can also put at risk some or all of Hardy’s licences enabling it to explore and/or produce, and incur fines or penalties as well as criminal sanctions against the Company and/or its officers. Consequently, production delays and declines from normal field operating conditions may result in revenue and cash flow levels being adversely affected. The Group’s future success will depend, in part, on its ability to develop existing oil or gas reserves in a timely and cost-effective manner. The Group’s drilling activities may be unsuccessful and the actual costs incurred in drilling, operating wells and completing well workovers may exceed budget. The Group may be required to curtail, delay or cancel any drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions, compliance with governmental requirements and shortages or delays in the availability of drilling rigs and the delivery of equipment. The occurrence of any of these events could have a material adverse effect on the Group’s business, prospects, financial condition and operations.

Exploration Exploration activities are capital intensive and their successful outcome cannot be assured. Hardy undertakes exploration activities and incurs significant costs with no guarantee that such expenditures will result in the discovery of commercially deliverable oil or gas. The Group is exploring in geographic areas, where environmental conditions are challenging and costs can be high. The costs of drilling, completing and operating wells is often uncertain. As a result, the Group may incur cost overruns or may be required to curtail, delay or cancel drilling operations because of many factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions, compliance with environmental regulations, governmental requirements and shortages or delays in the availability of drilling rigs and the delivery of equipment.

Exploration licences Some licences held by the Group are solely exploration licences, and as such they have a limited term which is divided into three stages. Through each stage a portion of the licence will need to be relinquished. At the end of the term, if no commercial discoveries have been declared, the Group will be obliged to relinquish the entire licensed area.

Work programme Each of the Group’s India exploration licences requires minimum work programmes to be fulfilled within each phase of the licence. These may include seismic surveys to be performed, wells to be drilled and other data acquisition. Failure to comply with such obligations, whether inadvertent or otherwise, may lead to fines, penalties, restrictions and withdrawal of licences with consequent material adverse effects. With respect to each of the Group’s Nigeria assets, minimum work programmes are mutually agreed between the joint venture and the Government of Nigeria’s Department of Petroleum Resources. Failure to comply with such obligations, whether inadvertent or otherwise, may lead to fines, penalties, restrictions and withdrawal of licences with consequent material adverse effects.

Interruptions in availability of exploration, production or supply infrastructure The Group may suffer from delays or interruptions due to lack of availability of drilling rigs or construction of infrastructure, including pipelines, storage tanks and other facilities, which may adversely impact Hardy’s operations and could lead to fines, penalties, criminal sanctions against the Company and/or its officers or some or all of the Group’s licences being withdrawn. Delays in obtaining licences, permissions and approvals required by the Group in the pursuance of its business objectives, including construction of pipelines, storage tanks or other facilities could likewise have a material adverse impact on the Group’s business and the results of its operations.

Third party contractors and providers of capital equipment The Group contracts or leases services and equipment from third-party providers and suppliers. Such equipment and services can be in short supply and may not be readily available at the times and places

9 required. In particular, the Group utilises specialised offshore drilling rigs and various special-purpose vessels, of which there are a limited number relative to demand in the global and more specifically India region. In addition, the costs of third-party services and equipment have increased significantly over recent years and may continue to rise. This may, therefore, have an adverse effect on Hardy’s business. In addition, the failure of a third party provider or supplier of equipment or services could have a material adverse impact on the Group’s business and the results of its operations.

Climate The Group operates in areas with extreme and seasonal weather conditions, including severe storms and monsoons. Each of these climate conditions can adversely affect the Group’s operations.

Supply terms The Group has entered into an agreement with a third-party for the sale of oil production from the PY-3 field. If the purchaser does not pay promptly, the Group’s cash flow could be adversely affected.

Health, safety and the environment The Group’s operations are subject to laws and regulations relating to the protection of human health and safety and the environment. Failure, whether inadvertent or otherwise, by the Group to comply with applicable legal or regulatory requirements may give rise to significant liabilities. The Group’s health, safety and environment policy is to observe local and national legal and regulatory requirements. The terms of licences or permissions may include more stringent environmental and/or health and safety requirements. The obtaining of exploration, development or production licences and permits may become more difficult or be the subject of delay due to governmental, regional or local environmental consultation, approvals or other considerations or requirements.

Current and future financing The Group’s business necessarily involves significant capital expenditure. In addition, if the Group is required to provide further capital in pursuit of additional opportunities, the Group may have a need to seek further external debt and future equity financing. There is no guarantee that such additional funding, if required, will be available on acceptable terms at the relevant time. Furthermore, any additional debt financing may involve restrictive covenants which may limit or affect the Group’s operating flexibility. If additional funds are raised through the issue of equity or equity-linked instruments, Shareholders may experience a dilution in their percentage holdings in Ordinary Shares.

Pursuit of strategy The Group requires a significant amount of cash in order to fund its anticipated exploration, appraisal and development work programme to maintain its operations (including satisfying its field development capital expenditure obligations), and in addition to pursue its strategy of growth by acquisitions of additional fields and assets, and meet its liquidity needs.

Future licence acquisitions Part of the Group’s strategy is to increase its oil and gas reserves and production through strategic acquisitions of exploration and/or production licences at auctions held by the relevant governmental or similar body, and through asset or corporate acquisitions. Due to the limited amount of information available prior to an auction, it may not be possible to properly assess the potential and true value of the licence to be acquired. Where the Group acquires another company or its assets, and integrates operations and personnel, the pre or post-completion costs may render the value of any company or assets acquired to be less than the amount paid.

Uninsured risks Substantial damages may be claimed against the Group due to events arising from the inherently hazardous nature of its operations and omissions of sub-contractors. Any indemnities the Group may receive from such sub-contractors may be difficult to enforce if they lack adequate resources. The Group considers that the extent of its insurance cover is reasonable based on the costs of cover and, the risks associated with its business and industry practice. The Group’s insurance currently includes cover for

10 damage to or loss of certain production assets, insurance for out-of-control wells (including coverage for environmental damage caused thereby), third party liability coverage (including employer’s liability insurance) and directors’ and officers’ liability insurance, in each case subject to excesses, exclusions and limitations. The Group is unable to provide any guarantee that expenses relating to losses or liabilities will be fully covered by the proceeds of applicable insurance. Consequently, the Group may suffer material losses from uninsurable or insured risks or insufficient insurance coverage. The Group is also subject to the future risk of unavailability of insurance, increased premiums or excesses, and expanded exclusions. Currencies The Group reports the results of its operations and financial condition in US dollars. The share price of the Company will continue to be quoted on the London Stock Exchange in UK sterling. As a consequence Shareholders may experience fluctuations in the market price of the Ordinary Shares as a result of, amongst other factors, movements in the exchange rate between UK sterling and the US dollar. Foreign exchange risk The proceeds of the Group’s domestic oil and gas sales in India are received in US dollars. The majority of the Group’s expenditure requirements are in US dollars. The Group has general and administrative expenditure with respect to offices in India, United Kingdom, and Nigeria, therefore the Group is exposed to foreign exchange risk against Indian Rupees, Nigerian Naira and UK Sterling. The Group has no current plans to enter into ongoing hedging arrangements. As the Company will be listed on the London Stock Exchange, any funds which may be raised through the issue of share capital will be denominated in UK Sterling, however the majority of the Group’s capital expenditure will be in US dollars. Liquidity risk The Group’s cash requirements and cash reserves are projected for the Group as a whole and for each country in which operations are conducted. Whereas the Group currently has no debt, going forward the Group expects to meet these requirements through an appropriate mix of available cash and assets, equity funding and debt financing. The Group seeks to minimise the impact that any debt financings may have on its balance sheet by negotiating borrowings in matching currencies. Primarily, these are expected to be in US dollar denominations. The Group further mitigates liquidity risk by maintaining an insurance programme to minimise exposure to insurable losses. Commodity price risk Historically, oil prices have fluctuated widely and are affected by numerous factors over which the Group has no control, including world production levels, international economic trends, currency exchange rate fluctuations, expectations for inflation, speculative activity, consumption patterns and global or regional political events. The aggregate effect of these factors is impossible to predict. The production estimates for PY-3 and the oil prices estimated will vary depending upon market conditions, which are not within the control of the Group. The Group’s production in India sold to CPCL is based on the 14-day average (seven days prior and seven days after crude delivery) of Brent less $0.35. The Board has no immediate intention to enter into fixed-price, long-term marketing contracts. Pricing for production from future development assets in Nigeria has not been arranged. Although oil prices may fluctuate widely, it is the Group’s present policy not to hedge crude oil sales unless hedging is required to mitigate financial risks associated with any future debt financing or to meet its commitments. Over time, during periods when the Group sees an opportunity to lock in attractive oil prices, it may engage in limited price hedging. Due to the physical nature of gas, transportation has been limited to pipelines and thus monetisation is restricted to regional markets. This results in significant variation in the price realised, driven by regional variation in supply and demand. Recent investment in LNG infrastructure has increased the mobility of gas from regions of excess gas to markets with high demand. LNG and other monetisation options for stranded gas, such as GTL, are capital extensive and require large reserves. Numerous factors will affect future gas prices, including domestic supply, domestic economic growth, consumption patterns and the locations of gas field, of which all will have an impact on the price realised, but are still outside the control of the Group.

11 In India, government approval is required with respect to the pricing of natural gas sales contracts. Currently there is a limited market for gas in Nigeria. The primary market for gas in Nigeria is LNG.

Oil and gas industry competition The oil and gas industry is highly competitive, including in the regions in which the Group operates. The key areas of which the Group faces competition are: • acquisition of exploration and production licences at auctions or sales run by governmental authorities; • acquisition of other companies that may already own licences or existing hydrocarbon producing assets; • engagement of third party service providers whose capacity to provide key services may be limited; • purchase of capital equipment that may be scarce; and • employment of the best qualified and most experienced staff. The effects of this competition may result in higher than anticipated prices for acquisition of licences or assets, the poaching of key management or operatives, restriction on the availability of equipment or services as well as potentially unfair practices, including unconscionable pressure on the Group directly or indirectly or the dissemination of false or misleading information or rumours. Such competition may have an adverse effect on the Group and its prospects.

Decommissioning costs Licensees are invariably obliged under the terms of relevant licences or local law, to dismantle and remove equipment, cap or seal wells and generally make good production sites. Hardy’s financial statements for the nine months ended 30 September 2007 make provisions based on Hardy’s estimate of the decommissioning costs to be incurred at the end of the Group’s licences. These are estimates based on currently known facts and circumstances including the current extent of the Group’s operations. No guarantee can be given that such provisions shall in due course turn out to be sufficient.

Future litigation From time to time, the Group may be subject to litigation arising out of its operations. Damages claimed under such litigation may be material or may be indeterminate, and the outcome of such litigation may materially impact the Group’s business, results of operations or financial condition. While the Company assesses the merits of each lawsuit and defends itself accordingly, it may be required to incur significant expenses or devote significant resources to defending itself against such litigation. In addition, the adverse publicity surrounding such claims may have a material adverse effect on the Group’s business.

Speed of development There are numerous factors which may affect the success of the Group’s business which are beyond the Group’s control, including local, national and international economic, legal and political conditions. The Group’s business involves a high degree of risk which a combination of experience, knowledge and careful evaluation may not overcome. The operations of the Group in developing countries expose the Group to, among other things, political and currency risks. The Group has experienced significant growth and development in a relatively short period of time and expects to continue to grow as field operation activity and production increase. Management of that growth requires, among other things, stringent control of financial system and operations, the continued development of management controls and the training of new personnel. Failure to successfully manage the Group’s expected growth and development could have a material adverse effect on the Group’s business, results of operations or financial condition.

Procure appropriate drilling equipment Oil and natural gas development and exploration activities are dependent on the availability of drilling and related equipment in the particular areas where such activities will be conducted. Demand for limited equipment such as drilling rigs or access restrictions may affect the availability of such equipment to the Group and may delay its development and exploration activities. In the areas in which the Group operates there is significant demand for drilling rigs and other equipment. Failure by the Group to secure necessary equipment could adversely affect the Group’s business, results of operations and financial condition.

12 ECONOMIC AND POLITICAL RISK

India The Group’s principal current assets and operations are located in India where there may be risks over which it will have no, or limited, control. These may include economic, social, or political instability or change, hyperinflation, currency non-convertibility or instability and changes in laws affecting foreign ownership, government participation, taxation, working conditions, exchange control and custom duties as well as government control over domestic production.

Nigeria The Group has two assets and operations located in Nigeria. There are political, economic and other risks relating to Nigeria or to other countries in which it may operate in the future. Relinquishment obligations under applicable legislation and the terms of farm-in/farm-out contracts (associated with the marginal field concessions) may adversely affect the total amount of the Group’s Prospective Resources. Interpretation and application of the laws and regulations of the countries in which the Group operates can be uncertain and could adversely affect the Group. Crime and governmental or business corruption could significantly disrupt the Group’s ability to conduct its business and could materially adversely affect its financial condition and operations. The Group must comply with the regulatory regimes of the countries in which it operates, and such compliance may result in increased expenditure. The Group’s production may be constrained by production or export quotas. Western oil and gas companies may be perceived to be targets of criminal or terrorist activities. Criminal or terrorist action against the Group, its properties or facilities could have a material adverse effect on the Group’s business, operations or financial position. In addition, the fear of criminal or terrorist attacks against the Group could have an adverse effect on the ability of the Group to raise capital and adequately staff its operations or could substantively increase the costs of doing so.

REGULATORY APPROVAL

India Following the announcement of various discoveries, exploitation of discovered oil and gas deposits will involve the need to obtain licence or clearance from the relevant governmental authorities. In particular for the Group, future successful exploitation of deposits discovered in the CY-OS/2, GS-01, D9 and D3 exploration licences will be dependent upon development plan approval being granted by the GOI.

Nigeria The Group is subject to extensive government laws and regulations governing prices, taxes, royalties, allowable production, waste disposal, pollution control and similar environmental laws, the export of oil and many other aspects of the oil business. Although the Group believes it has good relations with the current government of Nigeria there can be no assurance that the actions of present or future governments in this country, or of governments of other countries in which the Group may operate in the future, will not materially adversely affect the business or financial condition of the Group. The Group’s current operations are, and future operations will be, subject to approval from governmental authorities and, as a result, the Group has limited control over the nature and timing of development and exploration of such properties or the manner in which operations are conducted on such properties. The Group’s marginal field farm-in/farm-out contracts and other contracts with the government and government bodies to explore and develop the properties are subject to specific requirements and obligations. If the Group fails to satisfy such requirements and obligations and there is a material breach of such contracts, such contracts could, under certain circumstances, be terminated. The termination of any of the Group’s contracts granting rights in respect of the properties would have a material adverse effect on the Group’s financial condition.

ENVIRONMENTAL FACTORS The Group’s operations are, and will be, subject to environmental regulation (with regular environmental impact assessments and evaluation of operations required before any permits are granted to the Group) in all the jurisdictions in which it operates. Environmental regulations are likely to evolve in a manner that

13 will require stricter standards and enforcement measures being implemented, increases in fines and penalties for non-compliance, more stringent environmental assessments of proposed projects and a heightened degree of responsibility for companies and their directors and employees. Compliance with environmental regulations could increase the Group’s costs. The Nigerian government has announced what is commonly known as the ‘‘Flares Down by 2008’’ policy that that will require petroleum producers to reduce the amount of natural gas that is flared in petroleum production. The Nigerian government has announced that the timing for compliance will be 2008. The government has stated that it will issue financial penalties for flaring of gas after this date. Should Hardy’s operations not be able to comply with this mandate, financial penalties may be levied. BUSINESS RELATIONSHIPS The Group relies significantly on strategic relationships with other entities in the oil and gas industries in India and Nigeria such as joint venture parties and farm-in partners, and also certain regulatory and governmental departments. The Group’s India joint venture agreements are subject to unanimous approval of proposed work programmes. Failure to obtain unanimous approval may result in the delay of execution of various work programmes. Such delays may have an adverse impact on the Group’s valuation. The Group has a minority interest in a number of non-operated assets in India. The Group has limited influence on the timing of commencement of exploration and development operations on these assets.

ATTRACTION AND RETENTION OF KEY EMPLOYEES The Group relies heavily on a small number of key individuals, in particular the executive Directors, for the operation of its day-to-day activities and implementation of its growth strategy. In addition, personal connections and relationships of its key management are important to the conduct of its business. The Group’s business and operations may be negatively affected by the departure of any of these individuals, or any of a number of other key employees. There can be no guarantee that the Group will be able to continue to attract and retain required employees.

RISKS RELATING TO INVESTMENT IN THE COMPANY’S ORDINARY SHARES Share prices may fluctuate from time to time for various reasons. As well as being affected by the Company’s actual or forecast operating results, the market price of the Ordinary Shares may fluctuate significantly as a result of factors beyond the Group’s control, including among others: • the change in world oil and natural gas prices; • the results of exploration, development and appraisal programmes and production operations; • changes in research analysts’ recommendations or any failure by the Group to meet the expectations of research analysts; • changes in the performance of the oil and gas sector as a whole and of any of the Group’s competitors; • fluctuations in share prices and volumes, and general market volatility; and • involvement of the Group in any litigation.

Sales of Ordinary Shares could adversely affect the Ordinary Share price The sale of a significant amount of Ordinary Shares in the public market, or the perception that such sales may occur, by any Director, member of the senior management or Shareholder, could create negative sentiment and may have a materially adverse effect on the market price of the Ordinary Shares.

Suitability of Ordinary Shares as an investment The Ordinary Shares may not be a suitable investment for all people receiving this document. Before making any investment, potential investors should consult an investment adviser, authorised by the FSA, who specialises in advising on the acquisition of listed securities. The value of the Ordinary Shares and the income received from them can go down as well as up and investors may get back less than their original investment.

14 FORWARD LOOKING STATEMENTS

Certain statements in this document constitute ‘‘forward-looking statements’’. Forward-looking statements include statements concerning the plans, objectives, goals, strategies and future operations and performance of the Company and the assumptions underlying these forward-looking statements. The Company uses the words ‘‘anticipates’’, ‘‘estimates’’, ‘‘expects’’, ‘‘believes’’, ‘‘intends’’, ‘‘plans’’, ‘‘may’’, ‘‘will’’, ‘‘should’’, and any similar expressions to identify forward-looking statements. Such forward-looking statements involve known and unknown risks, uncertainties and other important factors that could cause the Company’s actual results, performances or achievements to be materially different from any future results, performances or achievements expressed or implied by such forward-looking statements. Such forward-looking statements are based on numerous assumptions regarding present and future business strategies and the environment in which the Company will operate in the future. Among the important factors that could cause its actual results, performance or achievements to differ materially from those in the forward-looking statements include those factors set out in ‘‘Risk Factors’’ on page 7 and elsewhere in this document. These forward-looking statements speak only as at the date of this document. The Company is not obliged, and does not intend, to update or to revise any forward-looking statements, whether as a result of new information, future events or otherwise except to the extent required by any applicable law or regulation, including the Prospectus Rules, the Listing Rules and the Disclosure and Transparency Rules. All subsequent written or oral forward-looking statements attributable to the Company, or persons acting on behalf of the Company, are expressly qualified in their entirety by the cautionary statements contained throughout this document. As a result of these risks, uncertainties and assumptions, a prospective investor should not place undue reliance on these forward-looking statements.

15 DIRECTORS, SECRETARY AND ADVISERS

Directors Edward Paul Mortimer (Non-Executive Chairman) Perayya Sastry Karra (Chief Executive) Yogeshwar Sharma (Chief Operating Officer) Dinesh Dattani (Finance Director) Dr Carol Bell (Non-Executive Director) Pradip Panalal Shah (Non-Executive Director) all of the registered office

Company Secretary Richard Vanderplank

Registered Office 15-19 Athol Street Douglas Isle of Man IM1 1LB

Sponsor, Financial Adviser and Broker Arden Partners plc Nicholas House 3 Laurence Pountney Hill London EC4R 0EU

UK Solicitors to the Company Lawrence Graham LLP 4 More London Riverside London SE1 2AU

Isle of Man Legal Advisers Cains Advocates Limited to the Company 15-19 Athol Street Douglas Isle of Man IM1 1LB

Competent Person Gaffney, Cline & Associates Ltd. Bentley Hall Blacknest Alton Hampshire GU34 4PU

Auditors and Reporting Horwath Clark Whitehill LLP Accountants St Bride’s House 10 Salisbury Square London EC4Y 8EH

Principal Bankers Barclays Bank Plc 54 Lombard Street London EC3P 3AW and HSBC Holdings Plc 8 Canada Square London E14 5HQ

16 Registrars Equity Limited 15-19 Athol Street Douglas Isle of Man IM1 1LB

CREST Agent Computershare Investor Services (Channel Islands) Limited Ordnance House 31 Pier Road St. Helier Jersey JE4 8PW

17 PART 1 — INTRODUCTION TO HARDY OIL AND GAS PLC

Overview

Hardy Oil and Gas plc is an international oil and gas exploration and production company primarily focused on India and with some development interests in Nigeria. The Group has assembled an attractive portfolio of exploration, development and production assets.

Company history

The Company was originally incorporated under the name Jehan Energy Limited in 1997 by the founders, Messrs Sastry Karra and Yogeshwar Sharma, with the purpose of developing an oil and gas exploration and production business in India that built on the expertise and relationships of the management team. Management also aimed to exploit the substantial increase in demand for energy in India which followed liberalisation measures initiated by the Government of India in 1991, principally privatisation and the opening up of the economy to foreign companies, and the subsequent increase in economic activity.

Through asset acquisition, reserve optimisation and the development of strong working relationships, the Group has assembled a strategic position in the oil and gas basins on the east coast of India, and off the Saurashtra west coast near the Bombay High field. The Company has also acquired development assets in the Niger Delta of Nigeria, a proven oil province.

In September 1999 the Company acquired HEPI from a subsidiary of British-Borneo Oil & Gas plc.

In 2001, the Company purchased an 8.5 per cent. shareholding in HOEC.

The Company was subsequently renamed Hardy Oil and Gas Limited in 2001 and converted to a public limited company on 31 May 2005. On 7 June 2005, the Ordinary Shares were admitted to trading on the AIM market of the London Stock Exchange at a price per Ordinary Share of 144p.

On 5 August 2005 the Company announced that, through the India NELP-V round, it had been awarded the KG-DWN-2003/1 deepwater exploration licence (‘‘D3’’). HEPI had jointly bid for this licence with Reliance.

On 21 March 2006 the Company announced the acquisition of two licences in the Niger Delta of Nigeria, Oza and Atala. The Company acquired the interests via separate farm-in agreements entitling the company to a 40 per cent. working interest of the Oza field and a 20 per cent. working interest of the Atala field, subject to various terms and conditions.

On 8 January 2007 the Company announced a discovery in the Fan A-1 well, located in the Hardy operated CY-OS/2 licence.

On 15 May 2007 the Company announced the discovery of hydrocarbons in the Reliance operated B-1 well located on the Company’s GS-01 licence. Further drilling on this licence is expected in 2008.

On 10 August 2007 the Company announced the agreed appraisal programme of drilling three additional wells in the CY-OS/2 licence.

On 31 December 2007 the Company announced that a well test was successfully carried out on well no. 4 in the Oza field in Nigeria with flow rates averaging approximately 600 stbd of oil and average GOR of 5,466 scf/stb.

On 13 February 2008, the Company announced a gas discovery – Dhirubhai 39 – in the Reliance operated KGV-D3-A1 well located on the Company’s D3 licence. The Company also announced the spudding of a second well – KGV-D3-B1 – to evaluate Pleistocene and Late to Mid Miocene sandstone reservoirs. The well is expected to reach a TD of 2,740 m.

The Company has registered the established Hardy name and logo as trademarks in the UK, US, Australia, India and Canada.

18 Corporate Structure

The Group’s corporate structure is shown below. Hardy Oil and Gas plc (Isle of Man)

Hardy Oil (Africa) Limited Hardy Exploration & Production (India) Inc. (Isle of Man) (“HEPI”) 100% (Delaware, USA) 100%

Hardy Oil Nigeria Limited (“HON”) (Nigeria) 100%

Principal assets

The Group’s principal properties in India and Nigeria are as follows:

• In India, HEPI has a participating interest in one producing property and four exploration licences:

– PY-3: HEPI has an 18 per cent. interest in this field which accounts for all of the Group’s production. It is located offshore in shallow water and produces a light, high quality crude oil (49° API).

– CY-OS/2: HEPI has a 75 per cent. participating interest in this exploration licence. HEPI is the Operator of the licence.

– GS-01: HEPI has a 10 per cent. participating interest in this offshore exploration licence. Its partner Reliance is the Operator of the licence.

– D9: HEPI has a 10 per cent. participating interest in the D9 property, a deepwater offshore exploration licence. Its partner Reliance is the Operator of the licence.

– D3: HEPI holds a 10 per cent. participating interest in the D3 property, an offshore exploration licence. Its partner Reliance is the Operator of the licence.

• In Nigeria, HON has a working interest in two marginal fields:

– Oza: HON holds a 40 per cent. working interest in the Oza property, an onshore development property operated by a local company, Millenium. HON is the foreign technical partner for this property.

– Atala: HON holds a 20 per cent. working interest in the Atala property, an onshore development property operated by a local company, Bayelsa. HON is the foreign technical partner for this property.

19 Summary Table

Partners and Interest of Interest of Block Ref Area (km2) Hardy (per cent.) Water depth (m) Partners (per cent.) Operator Block CY-OS 90/1 PY-3 81 18 40 − 200 Tata 21 Hardy HOEC 21 ONGC 40 Oza OML 11 Oza 23 40 — Millenium 60 Millenium Atala OML 46 Atala 33.5 20 — Bayelsa 80 Bayelsa Exploration GS-OSN-2000/1 GS-01 8,841 10 80 – 150 Reliance 90 Reliance CY-OS/90-1 CY-OS/2 859 75 50 − 500 GAIL 25 Hardy KG-DWN-2001/1 D9 11,605 10 2,300 – 3,100 Reliance 90 Reliance KG-DWN-2003/1 D3 3,288 10 400 – 2,000 Reliance 90 Reliance Total 24,731

Notes:

1. Interest is shown on a participating interest basis pursuant to the relevant PSC, with the exception of the Oza and Atala licences where the interest is shown on a working interest basis.

2. Pursuant to the PSC for CY-OS/2, the licensee as stipulated by the GOI has a right to ‘‘back-in’’ for a 30 per cent. participating interest in the licence in the event that a commercial discovery is declared. Competent Person’s Report

GCA, an independent petroleum engineering consultancy, was commissioned to prepare estimates of the proved, probable, and possible oil, condensate, and sales gas reserves and the Contingent Resources and Prospective Resources contained within Hardy’s areas.

On 11 January 2008, the Company announced the following:

Summary of interests

The Group has interests in a number of assets in India and Nigeria that comprise production, potential development, discoveries and exploration.

The Indian assets are held through HEPI, a wholly owned subsidiary. The pertinent net participating interest (‘‘NPI’’) 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 (HEPI NPI 18 per cent.);

• Block CY-OS/2, located in the Cauvery Basin, offshore Tamil Nadu (HEPI NPI 75 per cent.);

• Block GS-01 (NELP II), located in the Bombay offshore Basin, to the West and Northwest of the ONGC operated Bombay High field (HEPI NPI 10 per cent.);

• Block D9 (NELP III) in the offshore Krishna-Godavari Basin (HEPI NPI 10 per cent.), located immediately to the east of Reliance’s 2003 gas discoveries in Block KG-DWN-98/3; and

• Block D3 (NELP V), in the offshore Krishna-Godavari Basin due west and some 50 km inshore of the Reliance concession mentioned above (HEPI NPI 10 per cent.).

The Nigerian assets are held through HON, a wholly owned subsidiary. Both blocks are onshore in the Niger delta basin and the pertinent net working interest (‘‘NWI’’) fractions are comprised of the following:

• Oza Field concession area, a formerly producing oilfield (HON NWI 40 per cent.) located in Oil Mining Licence (OML) 11 in Rivers State, and 33 km northeast of the city of Port Harcourt; and

• Atala concession area (Hardy NWI 20 per cent.), located in OML 46 in Bayelsa State in the Coastal Swamp Depobelt, less than 10 km from the coast.

20 RESERVES

The PY3 field is the Group’s sole producing asset from which revenues are derived. As at 30 June 2007, estimated gross and net entitlement oil Reserves were reported as follows:

Gross Oil Reserves MMbbl Net Entitlement Reserves MMbbl Proved, Proved, Proved + Probable + Proved + Probable + Proved Probable Possible Hardy Interest Proved Probable Possible PY-3 5.09 17.57 23.81 18% 0.82 2.69 3.44

CONTINGENT RESOURCES

The Company through acquisition and exploration has added to its resources categories additional hydrocarbons in both India and Nigeria. These Contingent Resources are summarised below:

Gross and net natural gas Contingent Resources Net Hardy Gross Contingent Contingent Resources Hardy Interest Resources Bcf (%) Bcf Licence 2C 2C GS-01, India 91.5 10 9.1 Atala, Nigeria 359.0 20 71.8 Total 450.5 80.9

Note:

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

Gross and net oil Contingent Resources Net Hardy Gross Contingent Contingent Resources Hardy Interest Resources MMbbl (%) MMbbl Licence 2C 2C CY-OS/2 (Ganesha-1 Deep Fan) 24.0 75 18.0 Oza field Nigeria 3.8 40 1.5 Atala field Nigeria 7.5 20 1.5 Total 35.3 21.0

Notes:

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

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

PROSPECTIVE RESOURCES

The Group also has an extensive exploration portfolio in both India and Nigeria. Based on technical data and evaluation, the Group’s hydrocarbon prospects are summarised below.

21 Gross and net natural gas Prospective Resources — Prospects

Gross Net Hardy Prospective Hardy Prospective Resources Interest Resources GCoS Bcf (%) Bcf (%) Licence Prospect Best estimate Best estimate CY-OS/2 Shree Miocene Channel 1 105.0 75 78.8 14 Shree Miocene Channel 2 132.0 75 99.0 14 GS-01 B2 103.0 10 10.3 30 B1/B2 66.0 10 6.6 30 S1 190.0 10 19.0 30 Prn 1 54.0 10 5.4 10 D3 KGD-1 71.0 10 7.1 25 KGD-2 113.0 10 11.3 20 KGD-3 66.0 10 6.6 20 KGD-11 143.0 10 14.3 20 KGD12 18.0 10 1.8 15

* It is inappropriate to report summed-up Prospective Resource volumes or to otherwise focus upon those of other than the ‘Best Estimate’ 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. A Prospect is defined as ‘‘A project associated with a potential accumulation that is sufficiently well defined to represent a viable drilling target’’. 3. In the event of a commercial discovery, ONGC has the option to back-into the CY-OS/2 licence at an interest of 30%.

Gross and net oil Prospective Resources — Prospects

Gross Net Hardy Prospective Hardy Prospective Resources Interest Resources GCoS MMBbl (%) MMBbl (%) Licence Prospect Best estimate Best estimate CY-OS/2 Ganesha — 1 Top fan 61.6 75 46.2 25 SE Four — Way Closure 7.0 75 5.3 25 Shree — Cretaceous 4.5 75 3.4 14

22 Prospective Resources — Leads

In addition to the Prospects listed above, a number of ‘Leads’ have been identified in Hardy’s acreage. Most notable of these is Block D9 in the Krishna Godavari deep water basin where three Leads have been identified from direct hydrocarbon indicators on seismic data. These Leads are at different geological horizons and are assessed below: Gross Net Hardy Prospective Hardy Prospective Resources Interest Resources GCoS Bcf (%) Bcf (%) Licence Lead Best estimate Best estimate D9 Upper Miocene 13,000 10 1,300 15 Middle Miocene 19,000 10 1,900 15 Oligocene 13,000 10 1,300 15

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

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. A ‘Lead’ is defined as 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’’. As such it must be appreciated that a Lead carries a higher risk than a Prospect. A complete copy of the CPR is set out in part 3 of this document.

Any references to Reliance International Limited within the CPR should be read as Reliance Industries Limited.

23 The Group’s India Properties

24 INDIA AND ITS OIL AND GAS INDUSTRY The Indian economy has performed strongly over the last few years, with the Reserve Bank of India estimating growth in GDP at 9.1 per cent. during the fiscal year 2007/8 (Source: Macroeconomic and Monetary Developments Mid-Term Review 2007-08, Reserve Bank of India). This rapid economic growth has led to a significant increase in demand for crude oil and natural gas, to the extent that India is currently the sixth largest consumer of oil and gas (Source: BP Statistical Review of World Energy, June 2007). In 2006, India’s world share of crude oil and natural gas consumption was 3.1 per cent. and 1.4 per cent. respectively (Source: BP Statistical Review of World Energy, June 2007). India is a net importer of crude oil and natural gas. In 2006, India consumed 2.58 million barrels per day of crude oil, yet it produced only 0.81 million barrels per day. Similarly, in 2006, India consumed 1.4 Tcf of natural gas, but produced only 1.1 Tcf (Source: BP Statistical Review of World Energy, June 2007). India started importing gas via LNG in 2004 at the Dahej terminal on the west coast of India. In 2006 India imported 282 Bcf of LNG. Upstream activity continues to remain at high levels with 42 active offshore rigs and several seismic vessels engaged in operations offshore on the east and west coasts. Several significant discoveries have been announced since the NELP was introduced. The commercial discovery of the Dhirubhai field by Reliance in the deepwater Krishna Godavari basin has demonstrated the existence of significant reserves in the basins of India. India’s regulatory framework has no restriction on repatriation of profits outside the country and the legal framework is based on British common law, which helps to attract non-Indian companies to operate in the region. INDIAN LICENSING AND FISCAL REGIME NELP provides upstream opportunities for companies in both the private and public sectors. It was first formulated by the GOI in 1997/8 to encourage Indian and foreign companies to undertake exploration and production activities. Since then there have been various rounds in the NELP programme, which has many attractive features, including: Fiscal and Contractual Terms • no payment of signature, discovery or production bonus; • no customs duty on imports required for petroleum operations; • no biddable minimum expenditure commitment during the exploration period; • no mandatory state participation by national oil companies and no mandatory carried interest in their favour; • freedom for the operator to market oil and gas in the domestic market; • biddable cost recovery limit of up to 100 per cent.; • sharing of profit petroleum based on investment multiple achieved by the operator; • income tax holiday for seven years from start of commercial production. INDIAN COMPETITION The exploration, development and production industry in India is highly competitive. In seeking to obtain desirable exploration and development prospects, in particular in the NELP licensing rounds, Hardy faces significant competition from Indian companies and major integrated and large independent multinational companies. Many of these competitors have access to financial or other resources substantially in excess of those available to the Group and may, accordingly, be better positioned to acquire and exploit prospects, hire personnel and market production. In addition, many of the Group’s competitors may be better able to withstand the effect of changes in industry conditions such as worldwide crude oil and natural gas prices and levels of supply and the application of government regulations, which may affect the Group’s business and which are beyond its control. DESCRIPTION OF PRINCIPAL ASSETS IN INDIA Cauvery Basin PY-3 Field This field, operated by HEPI, is located off the east coast of India some 80 km south of Pondicherry in water depths of between 40 and 200 m. The Cauvery basin developed in the late Jurassic/early Cretaceous period, and straddles the present-day east coast of India.

25 The licence, which covers some 81 km2, is currently the deepest producing subsea field in India and produces oil of high quality light crude (49° API). The field was developed using floating production facilities and subsea wellheads, a first for an offshore field in India. The PY-3 offshore oilfield was discovered on licence CY-0S 90/1 by ONGC in 1988 and, as a result of the development programme instituted by HEPI, was brought into production in November 1997. HEPI is the Operator of the PY-3 field, and is party to a PSC together with ONGC, TATA and HOEC. The participating interests (per cent.) for this licence are as follows:

Area HEPI TATA HOEC ONGC PY-3 18 21 21 40

PSC Terms Under a PSC with the GOI dated 30 December 1994, Vaalco Energy Inc. acquired an 18 per cent. share in the PY-3 licence. On 5 May 1995, Vaalco Energy Inc. assigned its rights in PY-3 to Vaalco Energy (India) Inc. Under this PSC and the related JOA, Vaalco Energy (India) Inc. became the Operator for the consortium, the other participants being HOEC, TATA and ONGC. Following the purchase by Hardy UK Holdings Ltd of Vaalco Energy (India) Inc. and the change of the latter company’s name to Hardy Exploration & Production (India) Inc., HEPI is now operator of this licence. The PSC expires in December 2019 but can be extended by mutual agreement for a further five years. The PSC requires that the gross revenue from oil sold is split into Cost Oil and Profit Oil. Cost Oil is that proportion of the revenue which is required to cover the costs incurred by the participants under the PSC. These consist of production costs, exploration costs and development costs and are all recoverable at a rate of 100 per cent. Unrecovered costs can be carried forward indefinitely. The remainder, the Profit Oil, is then split between the GOI and the participants. The apportionment of the Profit Oil is determined by reference to an investment multiple, which is based on the previous year’s activity. The investment multiple is the net revenue (gross revenue less Profit Oil paid to GOI minus production costs, less a deduction for notional tax) generated by the participants excluding ONGC divided by the total of exploration and development expenditure by the participants (excluding ONGC). A summary of this arrangement is as follows:

Profit Oil (per cent.) Investment multiple GOI Contractor Less than 1.5 10 90 Between 1.5 and 2 25 75 Between 2 and 2.5 40 60 Between 2.5 and 3 50 50 Between 3 and 3.5 60 40 Over 3.5 70 30 Currently the Profit Oil being paid to the GOI is 40 per cent. The Board expects this to increase to 50 per cent. for the following year from 31 March 2008.

Production and Operations Oil production from the PY-3 field in the nine month period ended 30 September 2007 averaged 4,560 bopd (821 bopd to the Group). The reduction in production was largely attributable to the natural decline of the field and, as announced on 10 August 2007, the shut-in of PY-3-3RL due to water breakthrough. Average daily production during October and November 2007 from the PY-3 field was 3,364 bopd. The PY-3 field came on stream at the end of November 1997 with 4 subsea wells (PY-3-2; PY-3-3; PD-3 and PD-4). Since production start-up, the field showed a steady decline from an initial production rate of 12,000 bopd, with abandonment originally expected in 2001. After the Company acquired HEPI in September 1999, it actioned measures to improve production and reduce costs. Following the acquisition of HEPI by the Company, HEPI initiated phase II of the field’s development by re-entering three vertical oil producers, drilling the two deepest lateral wells in India and putting them on production.

26 In November 2002, well PD-3 was lost when the drillship, after having successfully drilled and tested a lateral from the original vertical hole, was driven off location following a break in the anchor chain. The wellhead assembly was sheared off, but there were no injuries, loss of life or environmental damage. The well was made secure shortly thereafter. The successful re-drill of PD-3 in May 2004 increased production to 7,200 bopd which subsequently declined to 6,660 bopd as at 31 December 2004.

In September 2003, HEPI implemented water injection through the PY-3-2RL lateral well which has been essential for maintaining reservoir pressure and maximising recovery from the field. These developments have considerably extended the economic field life of the PY-3 field.

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. There are four sub-sea wells tied back to Tahara. Tahara has a three-stage crude oil separation system, with the first two stages being three-phase separators and the third stage a two-phase separator. Actual liquid processing capacity on Tahara is 20,000 bopd with 17 MMscfd of gas handling capacity.

For the nine month period ended 30 September 2007, average water injection rates were approximately 6,643 bwpd which is sufficient to maintain voidage replacement.

The field produces associated gas of 3.7 MMscfd. This produced gas is used as fuel gas, with excess gas being flared. Current stabilised crude oil is pumped from Tahara to Endeavor for storage and offloading to shuttle tankers.

Crude oil from the PY-3 field is sold to CPCL at its refinery in Nagapatsham, near Chennai. As operator of the field, HEPI advises CPCL of a date range during which cargo will be ready for lifting. CPCL then nominates a tanker to make the lifting and it is transferred to the CPCL terminal in approximately 100,000 bbl lots. The price at which the cargo is sold is determined under the crude oil sales agreement between CPCL and HEPI (as Operator), dated 26 September 2003 (and effective for all sales since 1 October 2001) which stipulates a price of Brent minus 35 cents per barrel, dependent on the crude meeting the quality standards stipulated in the agreement.

The PY-3 field joint venture has approved a US$92 million proposed phase III development programme which provides for the drilling of two additional lateral wells (one producer and one injector) and various gathering lines and facility upgrades. Drilling of these wells is not expected to commence before the first quarter of 2009 and additional production from the wells may not be expected until the latter part of 2009.

In light of the recent shut-in of the PY-3-3RL well, the PY-3 operating committee is evaluating several options and is expected to decide on an appropriate course of action in the first quarter of 2008.

CY-OS/2 Block

Licence block CY-OS/2 is located in the northern part of the Cauvery Basin immediately offshore from Pondicherry and covers approximately 859 km2.

In 2007, as part of the licence’s exploration phase III work commitment, HEPI drilled two exploration wells: Fan E-1 and Fan A-1. On 8 January 2007 the Company announced that the Fan A-1 well had discovered hydrocarbons. On 10 August 2007 the Company announced that it would proceed to the appraisal phase of the Fan-A1 discovery to establish the potential commerciality with the planned drilling of three further wells.

The CY-OS/2 licence comprises two retained areas (figure 3 on page 57 of this document). The northern area includes the Fan A-1 discovery. The southern area lies immediately adjacent to the HEPI operated PY-3 field, which had produced 21.18 MMstb oil by 30 September 2007. The PY-1 gas field lies within the southern part of the acreage and is expected to begin production by the first quarter of 2009.

HEPI has a 75 per cent. participating interest in and is the Operator of this licence, which is at present an exploration licence only. The participating interests (per cent.) in licence CY-OS/2 are as follows:

Area HEPI GAIL ONGC* CY-OS/2 75 25 —

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

27 The PY-3 oil field and PY-1 gas field are both contained within the CY-OS/2 licence but have been ring-fenced out, each with a separate PSC. The CY-OS/2 exploration licence has been under an approved phase III extension which expired at the end of March 2007. HEPI, as Operator of the joint venture, has fulfilled the phase III commitment work programme of 3D seismic surveys and drilling of two exploratory wells. Presently the licence is under appraisal phase, consisting of re-evaluation of existing 3D seismic data and drilling of three wells and two contingent (optional) wells. The drilling campaign is expected to commence in the last quarter of 2008.

The Board is presently considering farming out a portion of its participating interest in the licence.

PSC Terms

The PSC with the GOI for Block CY-OS/2, which was signed in November 1996, consists of three exploration phases and has recently been extended by a further 22 months.

The PSC provisions for Cost Oil and Profit Oil (as well as the calculation of the investment multiple to determine the apportionment of Profit Oil) are the same as licence PY-3. The actual entitlements to Profit Oil based on the investment multiple can be summarised as follows:

Profit Oil (per cent.) Investment Multiple GOI Contractor Less than 1.5 0 100 Between 1.5 and 2.0 10 90 Between 2.0 and 2.5 20 80 Between 2.5 and 3.0 30 70 Between 3.0 and 3.5 40 60 Over 3.5 50 50

There is a seven year tax holiday from the date of commencement of commercial production. Gross investment as of 30 September 2007 was approximately US$110 million.

Saurashtra Basin

GS-01

The GS-01 exploration licence is located in the Gurajarat-Saurashtra offshore basin off the west coast of India, directly adjacent to the prolific Bombay High oil field. The licence encompasses 8,841 km2, and water depths vary between 80-150 m.

In March 2001, Reliance and HEPI bid for 15 licences in the NELP-II licence bidding round and since then HEPI has retained an interest in one licence, being a 10 per cent. interest in the shallow water GS-01 Block, offshore Gujarat, with Reliance maintaining a 90 per cent. interest. The participating interests (per cent.) for this licence are as follows:

Area HEPI Reliance GS-01 10 90

Reliance is India’s largest private sector enterprise, with turnover in the year to 31 March 2007 of approximately US$27.2 billion, cash profits of approximately US$4.1 billion and net profit of approximately US$2.8 billion. Reliance’s operations include oil and gas exploration and production, refining, petrochemicals, textiles and retail.

28 PSC Terms The PSC with the GOI for licence GS-01 was signed in July 2001 with Reliance as the Operator and consists of three exploration phases. The term and corresponding work commitments for each phase are listed below:

Term Seismic Phase Yrs Expiry Wells 2D km 3D km2 I 3 06/06* 5 1,200 1,020 II 2 06/08 4 — — III 2 06/10 4 — —

* Phase I extended to July 2008 The PSC provisions for Cost Oil and Profit Oil (as well as the calculation of the investment multiple to determine the apportionment of Profit Oil) are the same as licence PY-3 except that: (a) a royalty is levied on crude oil and natural gas which is included in Cost Oil and recoverable at a rate of 100 per cent.; (b) the numerator of the investment multiple includes a deduction for royalty payments and excludes a deduction for notional tax.

Profit Oil (per cent.) Investment multiple GOI Contractor Less than 1.5 16 84 Between 1.5 and 2.0 40 60 Between 2.0 and 2.5 70 30 Between 2.5 and 3.0 79 21 Over 3.0 79 21 Under the PSC, a royalty is levied on the well-head value of crude oil and natural gas at a rate of 10 per cent. for offshore areas. In the case of an offshore area of depths greater than 400 m the royalty rate will be five per cent. of the well-head value of crude oil and natural gas for the first seven years from the date of commencement of commercial production in the field, then revert back to the 10 per cent. rate. There is a seven year tax holiday from the date of commencement of commercial production. Two exploration wells have been drilled to date. On 15 May 2007 Hardy announced that the GS-01-B1 well had discovered hydrocarbons in the mid-Miocene Limestone. The exploration well was drilled to a depth of 2,282 m MDRT and encountered natural gas and condensate within the mid Miocene Limestone over an interval from 1,988 m to 2,052 m MDRT. The two intervals selected for cased hole DST, were 1,988 m to 1,993 m and 2,019 m to 2038 m MDRT respectively. The test produced natural gas at a rate of 18.6 MMscfd together with 415 stb/d of condensate through a 56/64’’ choke with a flowing tubing head pressure of 1,346 psi. The potential extent and commerciality of the above discovery is yet to be established. Analysis of the well results will continue. The proposed programme for 2008 comprises of the acquisition of an additional 1,000 km2 of 3D seismic and the drilling of three further exploration wells which will meet the phase I work commitment for the exploration licence.

Krishna Godavari Basin

Block D9 – Exploration licence In August 2002, Reliance and HEPI bid for 15 licences in the NELP-III licence bidding round. The consortium was successful in being awarded 9 exploration licences. HEPI has retained an interest in the D9 licence, a deepwater block in the Krishna Godavari Basin, and has reassigned the remainder to Reliance. The retained licence is considered as having high potential as it is situated adjacent to the prolific Dhirubhai field discovered and operated by Reliance.

29 The licence encompasses 11,605 km2 in the Bay of Bengal where water depths vary from 2,300 m to 3,100 m. The participating interests (per cent.) for this licence are as follows:

Area HEPI Reliance D9 10 90 PSC Terms The PSC with the GOI for licence D9 was signed in February 2003 with Reliance as Operator and consists of three exploration phases. The term and corresponding work commitments for each phase are listed below:

Term Siesmic Phase yrs Expiry** Wells 2D km 3D km2 I 4 03/07* 4 2,100 1,650 II 2 03/09 4 — — III 2 03/11 4 — —

* Pursuant to the terms of the PSC, Reliance requested an initial 12 month extension to phase I of the licence. As per the ‘‘Policy for extension of exploration phases under NELP and pre-NELP production sharing contracts’’ an additional 18 month extension is available to the contractors of the PSC subject to various increases in the corporate guarantee and cash deposit requirements. ** The Ministry of Petroleum and Natural Gas is currently considering a three year moratorium on minimum work programmes for deep and ultra deepwater licences. The PSC requirements for Cost Oil and Profit Oil (as well as the calculation of the investment multiple to determine the apportionment of Profit Oil) are the same as licence GS-01. The actual entitlements to Profit Oil based on the investment multiple can be summarised as follows:

Profit Oil (per cent.) Investment Multiple GOI Contractor Less than 1.5 10 90 Between 1.5 and 2.0 16 84 Between 2.0 and 2.5 25 75 Between 2.5 and 3.0 34 66 Between 3.0 and 3.5 85 15 Over 3.5 85 15 A royalty is levied on the well-head value of crude oil and natural gas in the same method as licence GS-01. There is a seven year tax holiday from the date of commencement of commercial production. The oil and gas industry continues to experience significant shortage of specialty exploration and development equipment. This has been particularly apparent for offshore drilling ships capable of operating in water depths of greater than 2,000 m. As a result of this shortage HEPI’s D9 deepwater exploration licence has previously experienced delays in the drilling of the licence’s minimum work programme. As announced by the Company on 13 February 2008, after careful consideration of the current equipment shortage and the priority of the operator to complete offsetting commercial developments, the Board is of the view that drilling on the D9 licence is unlikely to commence until the latter part of 2008 at the earliest. However, as experienced with the D3 licence, windows of availability do occur and the Directors will endeavour to ensure that Shareholders are notified of developments on a timely basis.

Block D3 – Exploration licence In August 2005, Reliance and HEPI were awarded, under NELP V, a second licence in the deepwater Krishna Godavari Basin. The D3 licence encompasses an area of 3,288 km2, in water depths of 400 m to 2,100 m. Reliance is the Operator. The licence had approximately 410 km2 of existing 3D seismic data, which has been reprocessed. In addition Reliance has acquired approximately 2,000 km2 of additional 3D seismic data (phase I), which is currently being processed and interpreted. The Operator plans to acquire an additional 1,000 km2 in the fourth quarter of 2008 (phase II). Upon completion, the entire licence will be covered by 3D seismic.

30 The participating interests (per cent.) for this licence are as follows:

Area HEPI Reliance D3 10 90

PSC Terms

The PSC with GOI for D3 was entered into on 23 September 2005 and consists of three exploration phases. The term and corresponding work commitments for each phase are listed below:

Term Seismic Phase yrs Expiry Wells 2D km 3D km2 I 4 09/09 6 — 2,100 II 3 09/12 4 — — III 1 09/13 4 — —

The PSC requirements for Cost Oil and Profit Oil (as well as the calculation of the investment multiple to determine the apportionment of Profit Oil) are the same as licence GS-01. The actual entitlement to Profit Oil based on the investment multiple can be summarised as follows:

Profit Oil (per cent.) Investment Multiple GOI Contractor Less than 1.5 16 84 Between 1.5 and 2.0 28 72 Between 2.0 and 2.5 40 60 Between 2.5 and 3.0 76 24 Between 3.0 and 3.5 76 24 Over 3.5 85 15

Under the terms of the PSC, a royalty is levied on the well-head value of crude oil and natural gas in the same method as licence GS-01. There is a seven year tax holiday from the date of commencement of commercial production.

On 28 December 2007, the exploratory well KGV-D3-A1 commenced drilling in water depths of 715 m with the semi-submersible rig ‘‘C Kirk Rhein’’. The well was drilled to a depth of 1,937 m MDRT and encountered natural gas within the interval 1,513 m to 1,597 m MDRT with a gross sand thickness of 84 m.

One interval was selected for cased hole DST covering 1,565 m to 1,585 m MDRT and produced natural gas at a rate of 38.1 MMSCFD through a 120/64" choke.

Although early indications are encouraging, the potential extent and commerciality of the above discovery (‘‘Dhirubhai 39’’) are yet to be established. Analysis of the well results is ongoing.

The D3 joint venture has moved the rig ‘‘C Kirk Rhein’’ to a second location and has spudded the well KGV-D3-B1 to evaluate Pleistocene and Late to Mid Miocene sandstone reservoirs. The well is expected to reach a TD of 2,740 m.

31 The Group’s Nigeria Properties

32 NIGERIA AND ITS OIL AND GAS INDUSTRY Nigeria is Africa’s most populous country and largest oil producer. It ranks among the top ten countries in the world in terms of oil reserves, with proved crude oil reserves reported by OPEC to be 36.2 billion barrels (Source: BP Statistical Review of World Energy, June 2007). The Nigerian government has expressed its desire to increase the country’s proved oil reserves to 40 billion barrels by 2010 and is encouraging the continued development and exploration of the country’s oil resources to do so. Nigeria’s natural gas reserves are estimated to be 184 Tcf in 2006 (Source: BP Statistical Review of World Energy, June 2007). Many oil exploration and production activities in Nigeria are carried out under either joint ventures, PSCs, or marginal field initiatives. All of HON’s current assets are held in marginal fields. The Nigerian marginal fields comprise a number of ring-fenced fields located on concessions already awarded to joint ventures between international oil companies and NNPC (‘‘Joint Venture Parties’’). The marginal field criteria is a discovery recognised by the Nigerian Department of Petroleum Resources, having remained unproduced or undeveloped for a period of over 10 years. The Nigerian marginal fields are assigned to indigenous Nigerian oil companies who conclude farm-in agreements with the Joint Venture Parties and can, in turn, farm-out to other operators. The Nigerian marginal fields are subject to royalties and taxes payable to various parties including government agencies. The Niger Delta Basin is Africa’s largest and most prolific oil producing basin. It is also one of the world’s largest delta systems of tertiary age and covers an area greater than 75,000 km2. The Group currently holds a working interest in the onshore assets Oza and Atala. Pursuant to the Petroleum Amendment Act (number 23) of 1996 (the ‘‘Petroleum Act’’) both fields have been declared marginal fields and Millenium Oil and Gas Company Limited and Bayelsa Oil Company Limited (both indigenous oil companies) have been allocated respectively the Oza and Atala fields as part of the Federal Nigerian Government’s marginal field allocation. HON has entered into farm-in agreements with both parties in respect of development of these fields.

NIGERIA FISCAL REGIME Both Atala and Oza are subject to the provisions of the Petroleum Act, and the regulations thereunder, and the Petroleum Profit Tax Act (‘‘PPT Act’’). The fiscal terms of Nigerian marginal fields are the subject of legislative proposals to encourage participation of indigenous or locally owned companies in exploration and production.

DESCRIPTION OF PRINCIPAL ASSETS IN NIGERIA

Atala field

Field History Atala is located within OML 46 which is located in a mangrove swamp on the Dodo River, a coastal area of NW Bayelsa State. The concession area is 34 km2. The Atala field was discovered in 1982 with the drilling of the Atala-1 well to a total depth of 4,058 m. Hydrocarbons were encountered and the well was cased but not tested or completed. OML 46 is held by a joint venture operation between NNPC, SPDC, ELF Petroleum Nigeria Limited and Nigerian AGIP Oil Company Limited (the ‘‘OML 46 Joint Venture Parties’’). Pursuant to a farm-out agreement dated 27 April 2003 between the OML 46 Joint Venture Parties and Bayelsa, (‘‘Atala Farm-out Agreement’’), Bayelsa is the operator of the Atala field and has responsibility for undertaking the exploration, prospecting, winning, working and carrying away of petroleum in respect of the Atala field. The terms of this agreement are for an initial five year period from 27 April 2004, subject to an extension of the term of the Atala Farm-out Agreement if approved by the Nigerian Department of Petroleum Resources.

Farm-In Agreement On 28 July 2005 HON entered into a farm-in agreement with Bayelsa (‘‘Atala Farm-in Agreement’’) pursuant to which Bayelsa agreed to farm out a 20 per cent. participating interest in the Atala field to HON.

33 HON also agreed to act as technical partner for the development and operation of the Atala field. The terms of this agreement are for an initial five year period from 27 April 2004 with the possibility to extend the term if the Atala Farm-out Agreement is approved by the Nigerian Department of Petroleum Resources. The working interests (per cent.) of the field are as follows:

Area HON Bayelsa Atala 20 80 Under the terms of the Atala Farm-in Agreement, HON agreed to pay, as consideration, a sign-on fee of US$2.5 million. HON paid Bayelsa US$0.5 million upon receipt of assignment. The outstanding US$2.0 million shall be paid towards Bayelsa’s working interest share of initial expenditures incurred in carrying out the proposed development plan discussed below.

Royalties Under the terms of the Atala Farm-out Agreement Bayelsa and HON are required to pay royalties to the OML 46 Joint Venture Parties with respect to the production of crude oil at Atala. In addition, the Nigerian government also requires royalties to be paid with respect to the production of crude oil in the following manner: Field Range of Production (bopd)

Joint Venture Nigerian Parties government** From To (per cent.) (per cent.) — 2,000 2.5 2.5 2,001 5,000 3.0 2.5 5,001 10,000 5.5 7.5 10,001 15,000 7.5 12.5 15,001 25,000 tbd* 18.5 25,000 18.5

* to be determined between the parties ** as per gazette number 21 of 5 April 2006 Under the PPT Act, the Nigerian government also requires a petroleum profit tax (‘‘PPT’’) to be paid which is anticipated to be 55 per cent. of taxable profit. It is anticipated that taxable profit will be equal to revenue less royalties, non-capital costs and capital depreciation. The marginal field tax regime is set out below: PPT 55 per cent. Investment Tax allowance 20 per cent. Education Tax 2 per cent. Withholding Tax 5 per cent.

Prospectivity and development On the basis of logs and analogy with nearby fields, Atala -1 encountered at least seven hydrocarbon- bearing reservoirs, classified U1 to U7, with the lower sands primarily gas bearing. The nearest flow stations in the area are SPDC’s Kanbo flow station (7 km NE) and AGIP’s Clough Creek (11 km). A gas pipeline connects Kanbo to the main gas trunk line that goes to Forcados which can be considered for future gas sales. The field is covered by a 3D seismic data survey. A field development study has been completed by the operator Bayelsa utilising the available seismic, the Atala 1 well logs and regional data. The first stage development plan targets oil resources in the shallower U1.0, U2.0, and U4.0 reservoirs. The U7.0 and U3.0 sands are interpreted to have thin oil legs beneath considerable gas caps but due to problems with the logging, the U7.0 petrophysics requires well test confirmation. The proposed development plan involves two phases. The first phase envisages the re-entry and completion of the existing Atala-1 well and the drilling of a second lateral well to optimise oil drainage. AGIP operated Clough Creek field is the intended destination of Atala oil for evacuation.

34 The second phase will see both wells re-completed for gas production once a gas market is established. The second phase will target gas development once a gas market is established. At least two new gas wells will be drilled in the field for effective drainage of the estimated 395 Bscf gas resources.

Oza Field

Field History Oza Field is located on land in the north western part of OML 11, near Port Harcourt. The concession area is 20 km2. The field was discovered in 1959 with the discovery well, Oza-1, drilled to a depth of 3,279 m. The well was proposed to test a separate anticlinal culmination on the south-eastern extension of the Imo River-Igrita trend. The hydrocarbon-bearing sands found in Oza are correlatable with the oil-bearing sands discovered in Imo River wells. Subsequently, three other wells were drilled in the field. Oza-2, an appraisal well, was drilled to a total depth of 11,000 ft and confirmed the lateral extent of some intervals found in Oza-1. Oza-3, another appraisal well, was drilled to TVD 11,000 ft in October 1974. At the time of award of the field, the field had been shut in from 1983 due to declining oil production and increasing GOR. OML 11 is held by a joint venture operation between NNPC, SPDC, ELF Petroleum Nigeria Limited and AGIP (the ‘‘OML 11 Joint Venture Parties’’). Pursuant to a farm-out agreement dated 27 April 2004 (the ‘‘Oza Farm-out Agreement’’) between the OML 11 Joint Venture Parties and Millenium, Millenium is the operator of the Oza field and has responsibility for undertaking the exploration, prospecting, winning, working and carrying away of petroleum in respect of the Oza field. The terms of this agreement are for an initial five year period from 27 April 2004 subject to an extension of the Oza Farm-out Agreement if approved by the Nigerian Department of Petroleum Resources.

Farm-In Agreement On 27 June 2005 HON entered into a farm-in agreement with Millenium (the ‘‘Oza Farm-in Agreement’’), pursuant to which it was agreed that Millenium would farm-out a 40 per cent. participating interest in the Oza field to HON. HON also agreed to act as technical partner for the development and operation of the Oza field. The terms of this agreement are for an initial five year period from 27 April 2004 with the possibility to extend the term if the Oza Farm-out Agreement is approved by the Nigerian Department of Petroleum Resources. The working interests (per cent.) of the field are as follows:

Area HON Millenium Oza 40 60 Under the terms of the Oza Farm-in Agreement, HON has paid as consideration for the interest in Oza US$433,453 to Millenium. In addition, HON is required to fund the initial work programme for Oza. The initial work programme is defined as necessary operations to initiate commercial production.

Royalties The Oza marginal field is subject to a tax and royalty regime. The primary taxation is the profit petroleum tax and various withholding and education taxes. Taxes and royalties are calculated in the same manner as the Atala field (see table above).

Prospectivity and Development The field has cumulatively produced approximately 1.0MMstb from four open zones of three wells targeting three reservoirs, M5.0, L9.0 and M2.1, with the principal reservoir being M5.0. The production was flowed to Imo River-1 flow station through an Oza flow station and connecting pipeline. Field visits and follow up with SPDC have confirmed that these have been subsequently decommissioned by SPDC. Hence, at present, Oza has three abandoned wells in the field. Since taking over the field in 2004, Millenium as operator, along with Hardy, as technical partner, has completed a number of field operations and other studies. The log data of existing wells have been

35 re-analysed both internally and through third party study to identify potential re-completion targets. There is existing 3D seismic covering the Oza field. Negotiations between SPDC and Millenium for the acquisition of this data are ongoing. The Oza joint venture has proposed a phased development programme. The first phase envisions installinga9km6"pipeline to SPDC Isimiri FS through multiphase flow and separate oil, gas and water at SPDC’s Isimiri Flowstation. Associated gas from Oza field will be comingled with associated gas from the Isimiri field and piped through a 15 km 6" gas pipeline from Isimiri to Imo River. The existing wells will be put on production and wells no. 4 and 1 may be dually re-completed and new, shallower zones opened up for production. The second phase will target drilling new development wells after review of the field production performance, study of the 3D seismic and completion of integrated studies. Experiences of other operators of similar marginal fields suggest that horizontal wells in thin Oza oil reservoirs will substantially improve performance. On 31 December 2007 the Company announced that a well test was successfully carried out on well no. 4 with flow rates averaging approximately 600 stbd of oil average GOR of 5,466 scf/stb.

Shareholding in Hindustan Oil Exploration Company Limited As at 30 November 2007, Hardy held 6,657,694 shares or approximately 8.5 per cent. of the issued share capital of HOEC which is listed on both the National Stock Exchange of India and the Bombay Stock Exchange. As at 31 December 2007, HOEC had a market capitalisation of approximately US$327 million. All of HOEC’s operations are in India and are predominantly in the Cauvery Basin: • a 100 per cent. operating interest (subject to GOI approval) in the PY-1 field. This gas field is to the north of and adjacent to the PY-3 field (which is operated by Hardy); • a 21 per cent. non-operating interest in the PY-3 field (which Hardy operates and in which it has an 18 per cent. interest as discussed above); • an 80 per cent. operating interest in the exploration area CY-OSN-97/1; and • an 40 per cent. participating interest in AAP-ON-94/1 licence in Assam. The Group had been involved in litigation against HOEC. However, the Group’s defence of its pre-emption rights relating to a shareholder agreement, dated 14 October 1998, was not upheld by the London Court of International Arbitration. There are currently no outstanding claims or counterclaims relating to Hardy’s interest in HOEC. On 20 July 2007 HOEC announced that the HOEC Board of Directors had approved a rights issue for an amount not exceeding Indian Rupee 6,150 million. On 7 November 2007 HOEC announced that the HOEC board of directors had fixed the issue price at Rs. 117 per share and entitlement ratio of two equity shares for every three equity shares held. In early January 2008, HOEC completed the rights offering. Hardy participated in the rights offering, resulting in an acquisition of 4,438,462 additional shares in HOEC and a cash outlay of approximately $13.2 million. In December 2007 and January 2008, Hardy sold 4,981,411 shares in HOEC realising proceeds of approximately $20.6 million. On 14 February 2008, Hardy owned 6,114,745 shares of HOEC with a market value at such date of approximately $17.3 million and representing approximately 4.7 per cent. of the entire issued share capital of HOEC.

36 In addition, the Board envisages that during 2008 the Group’s exploration programme will accelerate and the Board expects to drill on all three of HEPI’s non-operated exploration licences in India. Hardy will also continue to assess investment opportunities that will complement the Group’s asset portfolio. The Group’s main focus remains in India where it has assembled its exploration and production team. Hardy is looking forward to a number of specific initiatives for 2008: • D3 – evaluating the results of the first successful well and the second follow up well, processing seismic and shooting additional seismic on the block; • GS-01 — initiating acquisition of an additional 1,000km2 of 3D seismic in the first quarter of 2008 and commence drilling of three additional wells in the second quarter of 2008; • D9 – spudding of the first well during the latter half of 2008 at the earliest. Other activity will be subject to various approvals and availability: • PY-3 phase III — subject to rig availability, begin the phase III development plan with the drilling of one development well and a water injection well to extend the field life, and potentially add recoverable reserves; • CY-OS/2 — subject to securing an appropriate offshore drilling rig, HEPI may commence appraisal drilling in the last quarter of 2008; • Oza — subject to agreement with third-parties and government approvals, HON may initiate the first phase development programme with installation of pipeline and production facilities. It is thought that sustainable production may begin by the second quarter of 2009. On 13 December 2007 the Indian Ministry of Petroleum & Natural Gas announced the launch of NELP-VIII. This NELP round offers a total of 57 oil and gas exploration licences comprising 19 in deep water, nine in shallow water and 29 onland blocks. Closing of bidding has been set for 11 April 2008.

DIVIDEND POLICY The Directors do not expect the Company to pay any dividends in the foreseeable future, and in any event not until such time as it is prudent to do so, having regard to the level of revenue generated by the Group’s operations and the retained earnings required to fund its operations and exploration and development programmes. For the foreseeable future, any earnings will be reinvested in developing the businesses of the Group.

CITY CODE At the time of the Company’s original flotation on AIM, the Panel confirmed that it considered the place of central management of the Company to be located outside the UK and the Isle of Man, and accordingly it was not subject to the City Code. However, the City Code applies to all companies which have their registered offices in the Isle of Man and have their securities admitted to trading on a regulated market in the UK irrespective of their place of central management. Therefore following Admission, Hardy will become subject to the provisions of the City Code.

CORPORATE SOCIAL RESPONSIBILITY (‘‘CSR’’) The Group’s guiding principles are to be ethical and act with integrity in the communities where it works, and to respect cultural, national and religious diversity. Based on mutual respect and understanding, the Group has built enduring relationships with the Indian Government, local authorities, partners and business associates. Respecting the rich cultural diversity of the region, the Group strives to protect the environment, taking into consideration the unique requirements of the region and local working practices to achieve optimum performance and timely delivery of projects. CSR is a fundamental part of implementing the Group’s corporate strategy and has both practical and ethical dimensions. It includes managing business concerns, such as risk, enhancing reputation in conjunction with investing in the community, and creating a place where people feel good about working. The Group contributes to community and social development by carrying out its business activities in such a manner that provide energy and infrastructure, employment, skills development and trade to the areas in which the Group operates.

37 HEALTH, SAFETY AND ENVIRONMENT (‘‘HSE’’) The Board has tailored the Group’s HSE policy and management system taking reference from world class operations to suit Indian conditions. Safety, security and emergency procedures have been incorporated into the weave of the Group’s operations. The central HSE Committee and Environment Management Committees meet on a monthly basis to assess and monitor compliance. The Group regularly undertakes internal and external HSE audits, including pre-mobilisation HSE audit of rigs and vessels. The Group undertakes periodical environmental marine monitoring around production facilities and around the drilling locations. Prompt compliance with applicable regulations by the Group has been recognised by concerned agencies. The Board believes that prevention of accidents, ill health, and protection of the environment, are essential to the efficient operation of its business. The Board is committed to high standards of health, safety and environmental protection. These aspects command equal prominence with other business considerations in the decision making process. Health, safety and environmental protection are responsibilities shared by everyone working for the Group, and the full support of all the Group’s staff, corporate partners, and contractors is vital to the successful implementation of this policy. The Board will ensure that personnel are aware of their delegated health, safety and environmental responsibilities and are properly trained to undertake them diligently. The Board aims to ensure that the necessary resources are provided to support this policy fully and to seek continuous improvement in performance. High HSE standards and constant grass roots level interaction give the Group the awareness of local communities’ sensibilities and needs. With an awareness driving the commitment, the Group provides its expertise and resources, wherever required, to be a responsible Company.

CREST CREST is a paperless settlement procedure enabling securities to be evidenced otherwise than by a certificate and transferred otherwise than by a written instrument. The Articles permit the holding of Ordinary Shares under the CREST system. The Company’s Ordinary Shares were admitted to CREST on 7 June 2005, the date that the Ordinary Shares were admitted to trading on AIM. Settlement of transactions in the Ordinary Shares following Admission may continue to take place within CREST if any Shareholder so wishes. However, CREST is a voluntary system and holders of Ordinary Shares who wish to receive and retain share certificates will be able to do so.

REASONS FOR ADMISSION TO THE OFFICIAL LIST The Group has grown significantly since admission to AIM in 2005 and the Board now considers, having regard to the Company’s market capitalisation, reserves and resource base, operations and production profile, the Official List to be a more appropriate platform than AIM for the continued growth of the Group. The Directors anticipate that a move to the Official List will increase the public awareness and recognition of the Group and will raise its profile and status within its sector. Furthermore, the Directors believe that in due course the admission to the Official List should assist in increasing the liquidity of the Company’s Ordinary Shares and increase its access to capital to fund its future exploration and development expenditures.

TAXATION Potential investors are referred to paragraph 11 of part 6 of this document for details of the taxation of the Company and of Shareholders in the UK and the Isle of Man.

SHAREHOLDERS WHO ARE IN ANY DOUBT AS TO THEIR TAX POSITION OR WHO ARE SUBJECT TO TAX IN JURISDICTIONS OTHER THAN THE UK ARE STRONGLY ADVISED TO CONSULT THEIR OWN PROFESSIONAL ADVISERS IMMEDIATELY.

38 PART 2 — MANAGEMENT

1. DIRECTORS The Board consists of six Directors in respect of whom brief biographies are set out below. E. Paul Mortimer (aged 74) — Non-Executive Chairman — Mr Mortimer has diverse board level experience and over 30 years’ experience in the oil, gas and mining industries. Mr Mortimer held various senior management roles through his 23 year career with Exxon Corporation including Senior Vice President of Exxon Minerals, New York, and Director and Vice President of Esso Argentina, Buenos Aires. After Exxon, he was responsible for Corporate Development and Coal at Newmont Mining Corporation in New York and was a Director of Peabody Coal. He has acted as a consultant to Morgan Stanley and a number of gold mining companies. Mr Mortimer was awarded a Rhodes Scholarship in 1957 and read Politics, Philosophy and Economics at Oxford. He also holds an MBA from the Harvard Business School. P. Sastry Karra (aged 65) — Chief Executive — Mr Karra, one of the two founders, has over 40 years’ oil and gas industry experience. He has held senior management roles at Occidental Petroleum Corporation and Petronas as well as earlier experience with Gulf Canada, Husky and Ashland. Mr Karra has held various consulting roles with the Boston Consulting Group and Santa Fe Resources. He was a Senior lecturer at the University of IBADAN from 1973 to 1976. Currently Mr Karra is the Founder and Chairman of the Association of Oil and Gas Operators of India and the Vice Chairman of the National Council of the Society of Petroleum Engineers. Yogeshwar Sharma (aged 56) — Chief Operating Officer — Mr Sharma, one of the two founders, has over 30 years of International oil and gas industry experience. He has previously worked with Energy Resources Conservation Board and Pan Canadian in Calgary, Canada and ARAMCO in Saudi Arabia. He has held senior technical positions at Schlumberger and Elf International, where he helped found the Elf Geoscience Research’ centre in London in 1991, Mr Sharma was an external examiner at Heriot Watt University for 3 years. Mr. Sharma was also responsible for the Group’s finance and administrative functions until 1 July 2007. Dinesh Dattani (aged 57) — Finance Director — Mr Dattani was appointed to the Board effective 1 July 2007. Mr Dattani is a Chartered Accountant with over 28 years of industry and corporate experience principally with international upstream oil and gas companies. Prior to joining Hardy, Mr Dattani has served in senior finance capacities with companies including Canoro Resources Ltd., Bow Valley Energy Ltd., Sherritt International Corporation, and Home Oil Company Ltd. all of which are/ were listed in either Canada and/or the United States. Dr Carol Bell (aged 49) — Non-Executive Director — Dr Carol Bell was appointed as an independent non-executive director in December 2005. Dr Bell has over 20 years’ experience in the oil and gas sector, most recently as the Managing Director of Chase Manhattan’s Investment Bank with responsibility for oil and gas. Prior to that she was the Global Head of J.P. Morgan’s Energy team in Equity Research. Dr Bell began her career in corporate planning and development with RTZ Oil and Gas and subsequently worked with Charterhouse Petroleum plc. She was awarded a PhD in the archaeology of ancient trade in May 2005. Dr Bell is a member of the Investment Advisory Committee of Gemini Oil and Gas (an oil and gas royalty fund). On 24 October 2007, Dr Bell was elected as a non-executive director of Revus Energy ASA. Pradip P. Shah (aged 52) — Non-Executive Director — Mr Shah is the founder and chairman of IndAsia Fund Advisors Private Limited. He established Indocean Fund in October 1994 with affiliates of Soros Fund Management and Chemical Venture Partners and founded and managed CRISIL, India’s first and largest credit rating agency in 1988. Mr Shah also assisted in setting up Housing Development Finance Company in 1977 and acts as consultant to USAID, the World Bank and the Asian Development Bank. Mr Shah holds an MBA from the Harvard Business School, and is a Chartered Accountant and Cost Accountant.

2. SENIOR MANAGEMENT R. Jeevanandam (aged 50) — Chief Financial Officer and director, HEPI — Mr Jeevanandam has over 25 years of oil and gas industry experience in finance and accounting. Mr Jeevanandam is a Chartered Financial Analyst, Certified Public Accountant and holds a Bachelor of Law degree. Previously Mr Jeevanandam has worked for ONGC as Joint Director Finance.

39 Ravi Venkateswaran (aged 57) — County Manager, HON — Mr Venkateswaran has over 31 years of oil and gas industry experience as an exploration and production geologist and manager. Mr Venkateswaran is a certified Petroleum Geologist, and holds a M.S in Geology and an MBA. Previously Mr Venkateswaran has worked for Gulf Oil Company, Schlumberger and HEPI.

3. EMPLOYEES As at 30 September 2007, the Group employed 48 people. The table below sets out the number of full-time employees, employed by the Group in each of the last three financial years, at the end of each such financial year: Year ended Year ended Nine month ended 31 December 31 December 30 September 2005 2006 2007 Directors 2 2 3 Administrative and technical 16 20 19 Operational 26 26 26 Total* 44 48 48

The table below sets out the number of full-time employees, employed by the Group in the United Kingdom, India and Nigeria in each of the last three financial years, at the end of each financial year: Year ended Year ended Nine month ended 31 December 31 December 30 September 2005 2006 2007 United Kingdom 7 7 8 India 37 37 36 Nigeria — 4 4 Total* 44 48 48

* Excluding non-executive directors

4. SHARE OPTION SCHEME The Directors believe that equity incentives are and will continue to be an important means of retaining, attracting and motivating Directors, senior management and key employees. Accordingly, in June 2005 the Board adopted the Share Option Scheme entitling the Company to award Options to employees. Details of the Share Option Scheme are set out in paragraph 6 of part 6 of this document. In the future it is intended to grant Options under the Share Option Scheme which generally vest in three equal instalments over a three year period but (due to the nature of the Group’s business) are not subject to any other performance conditions.

5. CORPORATE GOVERNANCE The Directors support high standards of corporate governance. Compliance with the Combined Code is not required for a company whose shares are admitted to trading on AIM and therefore the Company was not, prior to Admission, fully compliant with the Combined Code. However, the Directors have always taken note of its provisions and complied whenever it has been appropriate to do so. Other than in respect of the interests in Ordinary Shares of the non-executive Directors as detailed below, upon Admission the Company will comply with the provisions of the Combined Code. The Board currently comprises an independent non-executive chairman, three executive directors and two independent non-executive directors. The Board believes that all three non-executive directors are independent notwithstanding that all the non-executive directors hold Options and Mr Mortimer and Mr Shah hold Ordinary Shares (further details of which are set out at paragraph 7.4 of part 6 of the document). The Board meets on at least five occasions during the course of the year to review the Group’s operations, trading performance, budgets, funding, to set and monitor strategies, examine acquisition opportunities and report to shareholders. The Board has a formal schedule of matters specifically reserved to it for decisions. The roles of Chairman and Chief Executive are separate, and the responsibilities of Chairman and Chief Executive are independently defined. It is the Chairman’s responsibility to ensure that the Board is provided with accurate, timely and clear information in relation to the Group and its business.

40 The Combined Code recommends that the Board should appoint one of its independent non-executive Directors to be the senior independent director. The senior independent director should be available to Shareholders if they have concerns that contact through the normal channels of Chairman, Chief Executive or Finance Director has failed to resolve or where such contact is inappropriate. Dr Carol Bell is the Board’s existing senior independent director and will continue in this role following Admission. The Board has appointed an Audit Committee, a Remuneration Committee and a Nomination Committee, each of which has defined terms of reference which are summarised below. Each committee and each Director has the authority to seek independent professional advice where necessary to discharge their respective duties in each case at the Company’s expense. In addition, each Director and committee has access to the advice of the Company Secretary, Richard Vanderplank of Equity Limited.

Audit Committee The Audit Committee is chaired by Carol Bell and its other members are Paul Mortimer, and Pradip Shah. The Audit Committee is responsible for a wide range of financial matters and will, following Admission, meet at least two times a year. It monitors the controls that are in place to ensure the integrity of the financial information reported to shareholders. The Audit Committee also oversees the relationship with the external auditor, reviews the scope and results of audits and provides a forum for reporting by the Group’s auditors. The Audit Committee also focuses on compliance with legal requirements, accounting standards and the Listing Rules and the Disclosure and Transparency Rules and ensures that an effective system of internal control and risk management systems are maintained. The ultimate responsibility for reviewing and approving the annual report and accounts and the half-yearly reports nevertheless remains with the Board. The Executive Directors attend meetings of the Audit Committee through invitation.

Remuneration Committee The Remuneration Committee is chaired by Paul Mortimer and its other members are Sastry Karra and Pradip Shah. The Remuneration Committee, which will, following Admission, meet at least two times a year, considers remuneration policy and the employment terms and remuneration of the Executive Directors and senior management. The Remuneration Committee’s role is advisory in nature and makes recommendations to the Board on the overall remuneration packages for Executive Directors in order to attract, retain and motivate high quality executives capable of achieving the Group’s objectives. The Remuneration Committee also reviews proposals for the share option plans and other incentive plans, makes recommendations for the grant of awards under such plans as well as approving the terms of any performance related pay schemes. None of the Directors participates in any discussion or votes on any proposal relating to his own remuneration. The Board’s policy is to remunerate the Group’s senior executives fairly and in such manner as to facilitate the recruitment, retention and motivation of suitably qualified personnel. The remuneration of the non-executive Directors is determined by the Chairman and the executive Directors outside the framework of the Remuneration Committee.

Nomination Committee The Nomination Committee is chaired by Paul Mortimer and its other members are Sastry Karra and Pradip Shah. It will, following Admission, meet at least twice a year. The Nomination Committee considers the structure, size and composition of the Board, retirements and appointments of additional and replacement directors, reviews succession plans for the Directors and makes recommendations to the Board on membership of the Board, its committees and other matters within its remit.

41 PART 3 — COMPETENT PERSON’S REPORT

CESR Guidance Gaffney, Cline & Associates III 1(b)

COMPETENT PERSON’S REPORT

Prepared for

HARDY OIL AND GAS PLC

JANUARY, 2008

The Americas Europe, Africa, FSU Asia Pacific and the Middle East 1360 Post Oak Blvd., Bentley Hall, Blacknest 80 Anson Road Suite 2500 Alton, Hampshire 31-01C IBM Towers Houston, Texas 77056 United Kingdom GU34 4PU Singapore 079907 Tel: +1 713 850 9955 Tel: +44 1420 525366 Tel: +65 225 6951 Fax: +1 713 850-9966 Fax: +44 1420 525367 Fax: +65 224 0842 email: [email protected] email: [email protected] email: [email protected]

and at Caracas – Rio de Janeiro – Buenos Aires – Sydney www.gaffney-cline.com

Hardy 42 E1741.01 Gaffney, Cline & Associates

TABLE OF CONTENTS Page No.

INTRODUCTION...... 1

SUMMARY...... 5

DISCUSSION...... 12

1. INDIA ...... 12

1.1 Cauvery Basin ...... 12

1.1.1 PY-3 Field...... 12 1.1.2 CY-OS/2...... 21

1.2 Bombay Basin (sometimes Mumbai Offshore Basin) ...... 30

1.2.1 Block GS-01...... 32

1.3 Krishna Godavari Basin...... 39

1.3.1 Block D9...... 40 1.3.2 Block D3...... 44

2. NIGERIA ...... 48

2.1 Niger Delta Basin...... 48

2.1.1 Oza Field...... 51 2.1.2 Atala Concession...... 54

3. ECONOMIC EVALUATION...... 60

3.1 Fiscal Systems...... 60 3.2 Cost Assumptions...... 61 3.3 Oil Pricing...... 61

4. QUALIFICATIONS...... 62

5. BASIS OF OPINION...... 63

Tables

1. Summary of Licence Areas ...... 6 2. Summary of Estimated Gross and Net Entitlement Oil Reserves as at 30th June, 2007...... 7 3. Summary of Hardy Reference Post-Tax Net Present Values (Base Case Scenario) as at 30th June, 2007 ...... 7 4. PY-3 Gross Production and Cost Profiles ...... 8

Hardy 43 Gaffney, Cline & Associates

TABLE OF CONTENTS (Cont’d) Page No.

5. Summary of Gross & Net Natural Gas Contingent Resources as at 30th June, 2007...... 9 6. Summary of Gross & Net Oil Contingent Resources as at 30th June, 2007 9 7. Summary of Gross & Net Natural Gas Prospective Resources as at 30th June, 2007...... 10 8. Summary of Gross & Net Oil Prospective Resources as at 30th June, 2007 11

Figures

1. Location Map of Hardy’s Interests in India ...... 2 2. Location Map of Hardy’s Interests in Nigeria...... 3 3. Location of PY-3 Field and Block CY-OS/2, Offshore Cauvery Basin, India...... 13 4. Cauvery Basin Lithostratigraphic Column ...... 14 5. Top PY-3 Depth Structure Map (December 2006) with Structural/ Stratigraphic Elements...... 16 6. PY-3 Field Monthly Oil Production (Last 13 Months) ...... 18 7. PY-3 Oil Production Performance and Forecast ...... 19 8. Block CY-OS/2 Seismic Lines Through Well Ganesha-1 (Previously Well Fan A-1)...... 23 9. Ganesha-1 Well Area Deep Fan Prospect (Target 2) ...... 25 10. Block CY-OS/2 Shree Prospect Outlines of the Three Targets...... 27 11. Block CY-OS/2 Shree Prospect Seismic Lines Showing Miocene, Eocene and Cretaceous Components...... 28 12. Bombay Basin Lithostratigraphic Column ...... 31 13. GS-01 Block Location...... 33 14. GS-01 3D area Depth Structure Map at Top Bassein Formation...... 35 15. Block GS-01 Seismic Line Through the B-1 and A-1 Locations...... 36 16. Block GS-01 Prospects B2 and S1 ...... 38 17. Blocks D9/D3 Post Mesozoic Stratigraphy...... 41 18. Location Map Showing D3 and D9 Licences...... 42 19. Block D9 Depth Map on Top Miocene...... 43 20. Block D3 Seismic Expression of Lead KGD-1...... 46 21. Niger Delta Basin Lithostratigraphic Column...... 49 22. Seismic 2D Dip Line 11-70-1-145 Across Oza Field ...... 50 23. Oza Field Depth to Top M5 Sand (Shell Nomenclature) ...... 52 24. Atala Concession 3D Seismic Dip Line Through Atala-1 Well ...... 56 25. Atala Concession Seismic Time Map Near Top U1.0 Sand...... 57

Appendices

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

Hardy 44 Bentley Hall Gaffney, Cline & Associates Ltd Blacknest, Alton Technical and Management Advisers to the Petroleum Industry Internationally Since 1962 Hampshire GU34 4PU United Kingdom Principals: Telephone: +44 (0) 1420 525366 William B. Cline Facsimile: +44 (0) 1420 525367 Peter D. Gaffney email: [email protected] Registered London No. 1122740 www.gaffney-cline.com

MIH/E1741.01/0461/kab 10th January, 2008

The Directors, Hardy Oil & Gas Plc, Lincoln House, 37-143 Hammersmith Road, London, W14 0QL

Dear Sirs,

COMPETENT PERSON’S REPORT (CPR)

INTRODUCTION

In accordance with the instruction letter of Hardy Oil & Gas Plc (Hardy) dated 4th April, 2007 Gaffney, Cline & Associates Ltd (GCA) has reviewed the petroleum interests owned by Hardy in India and Nigeria (Figures 1 and 2). These assets include producing properties, potential developments, discoveries and duly licensed exploration interests in India and Nigeria.

GCA understands that Hardy intends to apply to list its shares on the Main Market of the London Stock Exchange. This Competent Person’s Report is intended to be included in the Circular in connection with that application

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 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 Competent Person's Report (CPR).

Industry Standard abbreviations are contained in the attached Appendix I Glossary, some or all of which may have been used 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.

UNITED KINGDOM UNITED STATES SINGAPORE AUSTRALIA ARGENTINA MOSCOW 45 Gaffney, Cline & Associates

NagpurNagpur

GS-01 MumbaiMumbai

PunePune I N D I A

HyderabadHyde r abad

ChennaiChennai BangaloreBangalore ChennaiChennai

CY-OS/2 PY-3 Field

istan China

Pakistan Nepal Bhutan

Bangladesh

Myanmar 0 500 km IndiaIndia

n B a y o f Location Map of Hardy’s B e n g a l Hardy Block Interests Andaman Interests in India Sea

Sri Lanka Source: GCA/Petroview Proj. E1741.01 Jan 08 Checked: Fig. 1 Hardy 2 46 Gaffney, Cline & Associates

N I G E R I A

WarriWarri

Oza Field Atala

PortPort HarcourtHarcourt

0 100 Km SpainSpaSpainSpa Alge r ia LibyaLibya Egypt WesteWestern rn Sahara

Mauritania

Niger SenegalSenegal Hardy Interests SudanSudan TheThe GambiaGambia Chad Guinea-Bissau Niger Delta Basin Outline Guinea Benin Nigeria TogoTogo Côte Ghana LiberiaLiberia d'Ivoired'Ivoire Ghana Central African Republic Bight Cameroon ofof BeninBenin

Bight ofof BonnyBonny U Source: GCA/Petroview

Gabon Democratic Republic ofof thethe CongoCongo Location Map of Hardy’s Interests in Nigeria A t l a n t i c O c e a n Angola Proj. E1741.01 Jan 08 Checked: Fig. 2 Hardy 3 47 Gaffney, Cline & Associates

It must be clearly understood that any determination of reserves 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.

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 independent energy consultancy specialising in petroleum reservoir 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 directors of GCA have been, and continue to be, independent of Hardy in the services they provide to Hardy including the provision of the opinion expressed in this review. Furthermore, the directors of GCA have no interest in any assets or share capital of Hardy, or in the promotion of Hardy.

This report must only be used for the purpose for which it was intended.

Hardy 48 4 Gaffney, Cline & Associates

SUMMARY

Hardy has interests in a number of assets in India and Nigeria that comprise production, potential development, discoveries and exploration.

The Indian assets and the pertinent Net Working Interest (NWI) fractions are comprised of the following: x 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%); x Block CY-OS/2, located in the Cauvery Basin, offshore Tamil Nadu (Hardy NWI 75%); x Block GS-01 (NELP II), located in the Bombay offshore Basin, to the West and Northwest of the ONGC operated Bombay High field (Hardy NWI 10%); x Block D9 (NELP III) in the offshore Krishna-Godavari Basin (Hardy NWI 10%), located immediately to the east of Reliance's 2003 gas discoveries in Block KG-DWN-98/3; and x Block D3 (NELP V), in the offshore Krishna-Godavari Basin due west and some 50 km inshore of the Reliance concession mentioned above (Hardy NWI 10%).

The Nigerian assets are both onshore in the Niger Delta Basin and the pertinent Net Working Interest (NWI) fractions are comprised of the following: x Oza Field concession area, a formerly producing oilfield (Hardy NWI 40%) located in Oil Mining Licence (OML) 11 in Rivers State, and 33 km northeast of the city of Port Harcourt; and, x Atala concession area (Hardy NWI 20%), located in OML 46 in Bayelsa State in the Coastal Swamp Depobelt, less than 10 km from the coast.

These concession areas are all shown on the regional location maps, Figure 1 (India) and Figure 2 (Nigeria). A summary of licence areas and water depth ranges (where appropriate) is given in Table 1.

GCA has reviewed various data and technical studies presented by Hardy, including seismic interpretations and dynamic reservoir simulation studies, as well as studies performed by independent third parties and other information available from the public domain. GCA has visited the offices of Hardy in London during May and June, 2007 for discussions with technical and managerial staff. Based on the information made available, GCA has considered the assessments performed by the operators and other third parties 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. Also, GCA has not visited the site of Oza field and of Atala concession. It must be recognised therefore that any security risks and the condition of the production facilities have not been evaluated.

On the PY-3 producing field, GCA has determined Proved, Probable and Possible Reserves, together with reference Net Present Values (NPVs) attributed to each of the two higher independent Reserve categories (‘Proved’ and ‘Proved plus Probable’). On the development/exploration licences, GCA has determined Contingent Resources for the presently shut-in Oza Field and the Atala discovery.

Hardy 49 5 Gaffney, Cline & Associates

TABLE 1

SUMMARY OF LICENCE AREAS

Block/Field Operator Hardy Permit/PSC Permit/PSC Block Water NWI Granted Date Expiry Date Area Depth (m) (km2) PY-3, India Hardy 18% Dec 1994 Dec 2019 81 40 - 450 CY-OS/2, India Hardy 75% Nov 1996 Mar 2007 859 50 - 900 GS-01, India Reliance 10% Jul 2001 Jul 2008 8,841 80 - 150 D9, India Reliance 10% Feb 2003 Feb 2011 11,850 2,300-3,100 D3, India Reliance 10% Sep 2005 Sep 2013 3,288 400-2,100 Oza, Nigeria Millenium 40% Apr 2004 Apr 2009 23 onshore Atala, Nigeria Bayelsa 20% Apr 2004 Apr 2009 34 onshore

Additionally, a determination has been made as to the Prospective Resources that may be attributed to a number of undrilled Prospects, together with the associated geological chance of success (GCoS) that they may be found to contain hydrocarbons, and thereafter be at least regarded as a candidate for inclusion in the Contingent Resource category. A significant number of Leads have been identified in Blocks D-9 and D-3 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 technical and economic conclusions presented herein are based on the data provided and represent GCA’s opinions as of the effective date of 30th June, 2007. The conclusions are estimates based upon professional geoscience and engineering judgment and they will 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 30th June, 2007 are for the PY-3 producing field and summarised in Table 2. All categories of Reserve volumes quoted herein have been determined within the context of an economic limit test on the basis of a constant price and cost (pre-tax and exclusive of accumulated depreciation amounts) assessment prior to any Net Present Value analysis.

Net Present Value Summary

Net Present Values (NPVs) have only been attributed to ‘Proved’ and the ‘Proved plus Probable’ Reserves. The reference Post-Tax NPVs for the ‘Proved’ and the ‘Proved plus Probable’ cases are summarised in Table 3. GCA employed a ‘Base Case’ Brent price scenario and considered this to be reasonable for the purpose of examining a range of monetary values that could be attributable to the asset. All NPVs quoted are those exclusively attributable to Hardy's net entitlement interests in the property reviewed.

Production Forecasts

Forecasts of gross oil production and costs are summarised in Table 4.

Hardy 50 6 Gaffney, Cline & Associates

TABLE 2

SUMMARY OF ESTIMATED GROSS AND NET ENTITLEMENT OIL RESERVES AS AT 30th JUNE, 2007

Gross Oil Reserves, Net Entitlement Reserves MMBbl MMBbl Proved Proved Proved plus Hardy Proved plus Proved plus Probable Proved plus Probable Probable plus Interest Probable plus Possible Possible PY-3 5.09 17.57 23.81 18% 0.82 2.69 3.44

Notes: 1. Net Entitlements are Reserves based on an estimate of Hardy’s entitlement to Cost Oil plus share of Profit Oil. 2. No data were available with respect to any unrecovered costs brought forward or undepreciated balances.

TABLE 3

SUMMARY OF HARDY REFERENCE POST-TAX NET PRESENT VALUES (Base Case Scenario) AS AT 30th JUNE, 2007

Asset Reserves Reference Post-Tax NPVs Category (U.S.$ MM) 7.5% 10.0% 12.5% Proved 9.06 9.19 9.27 PY-3 Proved plus 23.44 22.30 21.13 Probable

Note: 1. Post-Tax values assume no prior tax position as at 30th June, 2007.

Hardy 51 7 Gaffney, Cline & Associates

TABLE 4

PY-3 GROSS PRODUCTION AND COST PROFILES

Proved Proved plus Probable Year Oil CAPEX OPEX Oil CAPEX OPEX Production Production MBbl U.S.$ MM U.S.$ MM MBbl U.S.$ MM U.S.$ MM 2007 1,473 25.20 1,595 13.26 25.20 2008 1,105 36.00 1,571 80.00 36.00 2009 881 36.00 1,656 36.00 2010 750 36.00 1,480 36.00 2011 659 36.00 1,344 36.00 2012 589 36.00 1,232 36.00 2013 531 36.00 1,138 36.00 2014 481 36.00 1,056 36.00 2015 438 36.00 980 36.00 2016 400 36.00 906 36.00 2017 367 36.00 850 36.00 2018 337 36.00 799 36.00 2019 299 36.00 752 36.00 2020 185 36.00 708 36.00 2021 668 36.00 2022 630 36.00 2023 594 36.00 2024 556 36.00 2025 339 36.00 Total 8,495 0.00 493.20 18,854 93.26 673.20 MBbl

Note: 1. Years are based on Hardy’s financial year that ends 31st March. 2. Costs are in 2007$

Resource Summary

Apart from the producing assets, Hardy holds licences with discoveries and a number of exploration areas. GCA audited the estimates of Contingent Resources as of 30th June, 2007 and these are discussed in Section 1.2.1 (GS-01/B1 area), Section 2.1.1 (Oza Field) and Section 2.1.2 (Atala discovery) of this report. See Tables 5 and 6 respectively.

In addition, GCA assessed Hardy’s estimates of Prospective Resources as of 30th June, 2007 and these are shown in Tables 7 and 8.

Hardy 52 8 Gaffney, Cline & Associates

TABLE 5

SUMMARY OF GROSS AND NET NATURAL GAS CONTINGENT RESOURCES AS AT 30th JUNE, 2007

Gross Contingent Resources Net Hardy Contingent Resources BCF BCF 1C 2C 3C Hardy 1C 2C 3C Interest GS-01/ 24.0 91.5 400.0 10% 2.4 9.1 40.0 B1area, India Atala, Nigeria 314.0 359.0 433.0 20% 62.8 71.8 86.6

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

TABLE 6

SUMMARY OF GROSS AND NET OIL CONTINGENT RESOURCES AS AT 30th JUNE, 2007

Gross Contingent Resources Net Hardy Contingent Resources MMBbl MMBbl 1C 2C 3C Hardy 1C 2C 3C Interest CY-OS/2- Ganesha-1 - 24 - 75 - 18 - Deep Fan Oza Field, 1.0 3.8 7.8 40% 0.4 1.5 3.1 Nigeria Atala, 6.4 7.5 7.9 20% 1.3 1.5 1.6 Nigeria

Note: 1. The primary Contingent Resource volume reported here is the 2C, or ‘Best Estimate’, value. 2. In the event of a commercial discovery, ONGC has the option to back-into the CY- OS/2 licence at an interest of 30%.

Hardy 53 9 Gaffney, Cline & Associates

TABLE 7

SUMMARY OF GROSS AND NET NATURAL GAS PROSPECTIVE RESOURCES* AS AT 30th JUNE, 2007

Net Hardy Prospective Gross Prospective Resources Resources Hardy GCoS Licence Prospect BCF W.I. BCF (%) (%) Low Best High Low Best High Estimate Estimate Estimate Estimate Estimate Estimate Shree CY-OS/2 Miocene - 105.0 - 75 - 78.8 - 14 Channel 1 Shree CY-OS/2 Miocene - 132.0 - 75 - 99 - 14 Channel 2 GS-01 B2 26.0 103.0 426.0 10 2.6 10.3 42.6 30

GS-01 B1/B2 30.0 66.0 153.0 10 3.0 6.6 15.3 30

GS-01 S1 69.0 190.0 619.5 10 6.9 19.0 62.0 30

GS-01 Prn1 22.0 54.0 137.0 10 2.2 5.4 13.7 10

D3 KGD-1 - 71.0 - 10 - 7.1 - 25

D3 KGD-2 - 113.0 - 10 - 11.3 - 20

D3 KGD-3 - 66.0 - 10 - 6.6 - 20

D3 KGD-11 - 143.0 - 10 - 14.3 - 20

D3 KGD-12 - 18.0 - 10 - 1.8 - 15

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

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. Dashes indicate insufficient data to perform audit. 3. Prospective Resources in CY-OS/2 are GCA estimates. 4. In the event of a commercial discovery, ONGC has the option to back-into the CY- OS/2 licence at an interest of 30%.

Hardy 54 10 Gaffney, Cline & Associates

TABLE 8

SUMMARY OF GROSS AND NET OIL PROSPECTIVE RESOURCES* AS AT 30th JUNE, 2007

Gross Prospective Resources Net Hardy Prospective Resources Hardy GCoS Licence Prospect MMBbl W.I. MMBbl (%) (%) Low Best High Low Best High Estimate Estimate Estimate Estimate Estimate Estimate

Ganesha-1 CY-OS/2 - 61.6 - 75 - 46.2 - 25 Top Fan SE Four- CY-OS/2 Way - 7.0 - 75 - 5.3 - 25 Closure Shree - CY-OS/2 - 4.5 - 75 - 3.4 - 14 Cretaceous

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

Hardy 55 11 Gaffney, Cline & Associates

DISCUSSION

1. INDIA

Hardy has five discrete assets offshore India as shown in Figure 1. Most of these lie in the Bay of Bengal on the eastern side of the sub-continent. In and beyond the Krishna-Godavari Basin, are the deepwater exploration blocks D3 and D9, while further south, in the Cauvery Basin is exploration licence CY-OS/2, within the geographical limits of which lies the producing field PY-3. On the western margin, in the Arabian Sea, lies licence GS-01 in the Bombay Basin.

1.1 Cauvery Basin

The Cauvery Basin is the sedimentary basin located on and offshore Tamil Nadu State, south-east India. It is the most southerly basin on the east coast and encloses an area of more than 50,000 km2, of which about half is onshore. The rift basin was formed during Late Jurassic/Early Cretaceous as a result of the break-up of eastern Gondwanaland. NE-SW trending horst and graben structures formed during this period and dominated the structural grain of the basin, following which these features were buried to form a single passive margin setting. The dominant structure was formed by a north/south dextral strike-slip movement between the main Indian sub-continent and Sri Lanka. The basement is Pre-cambrian (Archean), and sediment fill, which in places reaches a thickness of 7 km, ranges from Permo- Carboniferous to Recent. The NE-SW-orientated sub-basins characterising the Cauvery Basin are an en-echelon array of rift basins offset by basement highs. In the Hardy acreage lie the Ariyalur-Pondicherry and Tranquebar sub-basins, separated by the Porto Novo High (on which lies the gasfield PY-1) as shown in Figure 3.

Rifting in the Barremian-Aptian started with fluvio-lacustrine deposition in half- grabens followed in the early Albian by a marine transgression. The main extensional phase occurred in the mid-Albian, when faulting led to uplift and erosion. Material reworked at the basin edges flowed into the low sub-basinal areas as fault- scarp conglomerates. The existence of turbidite sand bodies downdip of organic marine shales constituted a viable petroleum exploration play. Rifting ceased in the Cenomanian or Turonian after which thermal subsidence predominated. The post-rift stratigraphy consists of packages of mainly shallow marine and fluvial sandstones and sand-rich carbonates, separated by unconformities (see the lithostratigraphic column of Figure 4).

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 4). 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.

1.1.1 PY-3 Field (Hardy NWI 18%)

CESR Guidance The PY-3 field is located in the Cauvery offshore basin. It commenced Para 132 production in November, 1997, and is presently the only producing oil field in

Hardy 56 12 Gaffney, Cline & Associates

Indian Craton

y Ganesha-1 Well r r

he Ic CY-OS-2 d n In o s a b –P b r u l u S a L-XIL-XI y i r A

NEYVELI CY-ONN2002/1CY-ONN2002/1

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

PY-1 Field

Porto Novo High BHUVBHUVANAGI.02 A NA GI.02 Fan E-1 Well

CY-ONN2004/1CY-ONN2004/1 Madanam High

h L-IL-I ig CYCY-ONN2002/2 -ONN2002/2 H n ia d MADANAM e PY-3 Field M CY-OS-90/1

L-IL-I (EXTN.)(EXTN.) T r a n q u e b a r S u b b a s I n

KALIKALI CY-ONN2004/2CY-ONN2004/2 KALIKALI MYILADUTHURAI

KUTHALAMKUTHALAM Karaikal High

istan China

0 30 Km

Pakistan Nepal Bhutan

Bangladesh LEGEND Myanmar

IndiaIndia Hardy Block Interests Oil Field n Gas Field B a y Gas Condensate Field o f Location of PY-3 Field and B e n g a l High Areas Block CY-OS/2, Offshore AndamanAndaman Sea Cauvery Basin, India

Sri Lanka Source: GCA/Petroview Proj. E1741.01 Jan 08 Checked: Fig. 3 Hardy 13 57 Gaffney, Cline & Associates

Regional / Basinal Play / Age Lithostratigraphy

Tectonic Events Unit Play Fairways Reservoir Source Seal

Post Mid- Miocene Unit 6 Indian plate collided with UNCONFORMITY Tibetan plate

Eocene to Niravi Play

Unit 5 Mid-Miocene Indian plate collided with UNCONFORMITY Eurasian plate/ basin tilt E Paleocene to Kamalapuram Eocene Unit 4

Deccan trap volcanism/ UNCONFORMITY basin tilt SE

Coniacian to Nannilam P O S T -O P F T R I Maastrichtian (PY-3 Reservoir) Unit 3

Madagascar separated from UNCONFORMITY India/Reactivation of Basement Highs

Albian/ Bhuvanagiri Cenomanian/

Unit 2 Turonian

UNCONFORMITY

Pre-Albian Syn Rift Unit 1 S Y N R I F T S Y Rifting of East UNCONFORMITY Gondwanaland + Fractured Basement Pre-Cambrian (PY-1 Reservoir) Basement

Cauvery Basin Lithostratigraphic Column

Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 4 Hardy 14 58 Gaffney, Cline & Associates

Production Licence CY-OS-90/1 (Figure 3). 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 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 PY-3 PETREL Project and seismic data, velocity cube, petrophysical summary, ECLIPSE model, plus all available data from the three producing wells and the injector well together with financial data, including PSC and cost data.

Geology & Geophysics

The PY-3 field is sited within the Tranquebar sub-basin between two paleo- highs plunging to the northeast. The regional dip for the shallower horizons is to the south-east, including the water bottom which is at the present day slope edge. 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 geologic 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. This is compounded by the rapidly-changing water bottom (40 m to 450 m).

Hardy defined 5 reservoir units, 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 5. The latter also shows the locations of existing and proposed development wells.

Following Hardy’s 2006 3D interpretation, additional volumes were attributed to the field in the south-west, north-east and core areas. The last 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 3D seismic dataset proved to be of fair to good quality and the new mapping resulted in substantially revised geological and reservoir models affecting STOIIP and resource estimates. There is a significant water-bottom change in the north/north-east part of the concession which materially influences the depth structure maps as a result of the depth conversion. A major contribution to the STOIIP increases derives from the time to depth conversion. A detailed examination of this depth conversion was undertaken by GCA. The general work flow for the two-way-time conversion to depth followed standard industry practices, using stacking velocities to compute smoothed average velocities which were tied to the wells to provide an average velocity cube with which to convert time mapping to depth.

Hardy 59 15 Gaffney, Cline & Associates

386000 388000 390000 392000 394000 396000 398000 1254000

Hardy Proposed Permeability Barrier 1254000 -3700 Northeast Area -3 Possible Additional 1252000 7 0 0 Potential

00 1252000 0 5 3 -370 - 00 6 -3 PY3-PD1 1250000 1250000 -3500 Upper Reservoir 00 Limit -36 PY-3-2RST-RL 1248000

-3500 1248000 Southwest Area PY-3-3-RL Approximate Possible Additional Stratigraphic Limit Potential Of Upper PY-3 0 0

0 1246000 PY3-1 4 0 -3 5 PY-3-PD3-RLPY-3-PD4 3 -

1246000 Core Area 0 0 50 330 -3 - 0 - 40 3 -3 5 1244000 0 -3600 0 PY3-4 1244000

-3600 1242000

0 PY3-11 1242000 350 -

386000 388000 390000 392000 394000 396000 398000

05 km

LEGEND Producing Well Proposed Producing Well Dry Hole Water Injector Proposed Water Injector Top PY-3 Depth Structure Map Oil Water Contact (3,483m) (December 2006) with Structural/Stratigraphic -3500 Depth Contour (mss) Elements

Source: Hardy/GCA Proj. E1741.01 Jan 08 Checked: Fig. 5 Hardy 16 60 Gaffney, Cline & Associates

The seismic, wells, velocity field and top and base of the PY-3 reservoir were validated. It is GCA's opinion that there exists a potential for error 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 3300 ms, which clearly impacts on the conversion to the depth structure map.

The average velocity map to the top of the PY-3 reservoir revealed a change in average velocity from 2,020 m/sec (450 m WD) in the north-east to 2,330 m/sec (80 M WD) in the south-east. This factor affects the STOIIP estimation to the north and north-east.

It is GCA's opinion that there remains uncertainty in the presence of debris flows in the west and southwest and questionable structural closure to the northeast. This has been thoroughly discussed and quantified in the report "3D Modelling and Uncertainty Analysis of the PY-3 Field, Cauvery Basin, India", Hardy Oil & Gas, Earth Decision, Sheevel Geo-Technologies, 2006. There also remains structural uncertainty within the main body of the field causing potential inaccuracy in defining the gross rock volume. Although the wells are tied, immediately beyond this control, and between the wells, the depth conversion process is still subject to considerable uncertainty. Between the wells, errors in depth can range up to 20 m and this is reflected in the variation in gross rock volume estimates. Such inaccuracies imply significant uncertainty in areas more remote from the well control, reinforcing GCA’s opinion that the STOIIP additions outside the well-controlled closure remain of low confidence. The 3D Modelling Report mentioned above concludes that the greatest area of uncertainty is in the north-east part of PY- 3.

An updated STOIIP was reported by Hardy in September, 2006 based on the revised mapping and considering the uncertainties in the north-east part of PY-3. These estimates were 114, 135 and 156 MMBbl at the Low, Best and High levels respectively. GCA is not aware of any further adjustment of STOIIP at this stage.

Production Performance

The PY-3 field has been producing since November, 1997. Production wells are tied back to a floating production facility and oil is exported by shuttle tanker. Water injection started in September 2003 (FDP phase II). As at 30th June, 2007 three wells were on production: PY-3-3-RL, PY-3-PD-S and PY-3-PD4, with water injection into the reservoir via the well PY-3-2-ST-RL. GCA reviewed wells and field performance up to end of June, 2007. To 30th June, 2007, 20.84 MMBbl have been produced. The overall field performance since mid 2004 has been relatively stable, with field oil rate averaging about 5,800 bopd and field gas oil ratio (GOR) about 1,200 scf/Bbl up to December, 2006. The field average oil rate, however, dropped to 4,960 bopd during the first six months of 2007 (Figure 6). This drop is attributed to recent water cut from well PY3-3RL. There was no water breakthrough at any of the three producers until January, 2007 (Figure 7).

Hardy 61 17 Gaffney, Cline & Associates

200

190

180

170

160

150

140

130 Total Monthly Production MBbl Production Total Monthly

120

110

100 Jun-06 Jul-06 Aug-06 Sep-06 Oct-06 Nov-06 Dec-06 Jan-07 Feb-07 Mar-07 Apr-07 May-07 Jun-07

PY-3 Field Monthly Oil Production (Last 13 Months)

Proj. E1741.01 Jan 08 Checked: Fig. 6 Hardy 18 62 CESR Guidance Para 132(b) Gaffney, Cline & Associates

14,000 1400

12,000 1200

Sep 26, 2003 Start Water Injection 10,000 1000

8,000 800

6,000 600 Oil Rate-bopd Water Rate -bwpd Water Rate 63

4,000 400

2,000 200

0 0 Jul-97 Jul-98 Jul-99 Jul-00 Jul-01 Jul-02 Jul-03 Jul-04 Jul-05 Jul-06 Jul-07 Jul-08 Jul-09 Jul-10 Jul-11 Jul-12 Jul-13 Jul-14 Jul-15 Jul-16 Jul-17 Jul-18 Jul-19 Jul-20 Jul-21 Jul-22 Jul-23 Jan-98 Jan-99 Jan-00 Jan-01 Jan-02 Jan-03 Jan-04 Jan-05 Jan-06 Jan-07 Jan-08 Jan-09 Jan-10 Jan-11 Jan-12 Jan-13 Jan-14 Jan-15 Jan-16 Jan-17 Jan-18 Jan-19 Jan-20 Jan-21 Jan-22 Jan-23

Oil Rate - 1P Oil Rate-2P Produced Water Rate

PY-3 Field Production Performance and Forecast

Proj. E1741.01 Jan 08 Checked: Fig. 7 Hardy 19 63 Gaffney, Cline & Associates

Previously, water injection was insufficient to maintain reservoir withdrawals and the wells were often choked back to control GOR. At present, Hardy is compensating the loss of oil rate from PY3-3RL by optimising choke setting for well PY3-PD3S that permits an increased oil rate and at the same time keeps GOR at a practical level.

Whilst maintaining a prudent reservoir management plan, Hardy is assessing the cause of the water production and determining the necessary remedial actions to arrest its rise. GCA reviewed PY3-3RL completion and its structural setting with respect to the injection well PY3-2 and GCA accepts that further analysis is required to assess the water production.

Dynamic Reservoir Modelling

Hardy’s previous history matched model predicts water breakthrough to occur in 2011. After recent water breakthrough in well PY3-3RL, Hardy has been updating its dynamic ECLIPSE reservoir model. However, the water production data collected to date are still insufficient to allow the establishment of a reliable history match. Hardy continues to analyse the water production to determine the scenario that best represents PY3 water cut performance.

The history match process up to September, 2006 has only been applied to the oil production and GOR because there have been no reservoir pressure data since 2004 and no significant water production. Updating the model history match by including the water production should add more confidence to the dynamic model.

Production Forecast

Hardy’s Phase III development of the PY-3 field envisages the drilling of a fourth production well and a second injector. Hardy’s approach to the estimates of remaining recoverable oil is based on the following two cases:

x Case 1: Do nothing; and x Case 2: Phase III, 1 new injector, 1 new producer.

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.

Oil Reserves

Proved Reserves

This is based on field performance and assumes a do nothing case where oil production is allowed to continue to decline at the current rates. The Gross Proved Reserves as at 30th June, 2007 are estimated at 5.09 MMBbl (0.82 MMBbl Net Entitlement to Hardy).

Hardy 64 20 Gaffney, Cline & Associates

Proved plus Probable Reserves

For the Proved plus Probable Reserves case, GCA considered field performance and incorporated Hardy’s Phase III field development plan. The resulting estimated Gross Proved plus Probable Reserves as at 30th June, 2007 are 17.57 MMBbl (2.69 MMBbl Net Entitlement to Hardy).

Proved plus Probable plus Possible Reserves

This is based on PY-3 field performance, Hardy’s Phase III activities, a work over of PY3-3RL and a notional recovery of 3.0 MMBbl from the PY-3-4 area that assumes a subsea tie back well to PY-3 area. GCA estimated Gross Proved plus Probable plus Possible Reserves are at 23.81 MMBbl (3.44 MMBbl Net Entitlement to Hardy).

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 3), 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 3).

The Block was awarded to Hardy 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 is under consideration by the Directorate General of Hydrocarbons (hereafter DGH).

12,000 line km of 2D seismic have been acquired, 1,381 km of which have been re-processed. Four 3D seismic surveys, excluding that gathered over PY-3, have been shot totalling almost 830 km2. Nineteen wells have been drilled (the majority by ONGC) and two fields, PY-1 and PY-3, have been discovered on the original block. The PY-1 field is a gas development, operated by Hindustan Oil Exploration Company and from which first gas is imminent. Hardy holds no direct working interest in the PY-1 field, although it has an 8.5% shareholding in HOEC.

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, proposed to the DGH on 2nd April, 2007 for its consideration as a discovery in probable slope fans of Cretaceous age. 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 3).

Hardy 65 21 Gaffney, Cline & Associates

The failure of the Fan E-1 well and the varied nature of the results in the discovery well Ganesha-1 described below, clearly illustrate that the pursuit of stratigraphic traps is inherently of high risk.

Well Fan A-1 (now Ganesha-1)

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

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 seismic sections of Figure 8 graphically show the mounded nature of the fans, and also imply the uncertainty relating to updip seal. 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 encountered both the Campanian sands (Top Fan Package – Target 1) and the Turonian sands (Deep Fan Package – Target 2). Between these was a Middle Fan Package, consisting of Santonian and Coniacian sands developed as thin intervals within the Kudavasal Shale Formation. Shows were observed in the cuttings while drilling through each sand: flow tests were run on the Deep Fan Package and the Middle Fan Package (2). According to the Final Geological Report for the well, the Top Fan Package, 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 package provided no representative formation fluid (though they revealed the presence of gas). Oil shows were encountered during drilling, at three (possibly four) zones in the Top Fan Package.

The Deep Fan Package (Bhuvangiri formation), occurred at 3,759 m MD as 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 to 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 Package, 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 unit: 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.

Hardy 66 22 Gaffney, Cline & Associates

NW SE PND-1-1 Ganesha-1 well well 4 km (approx)

(a) Arbitrary Line Through Wells PND-1-1 & GANESHA-1 (see Fig. 9 for location)

‘Mounded’ Seismic Facies

Top Main Fan Package (Target 1) Top Deep Fan Package (Target 2) Base Main Fan Package Base Deep Fan Package

WE Ganesha-1 well

Target 1 - 2936

3336 sand (b) Detail E-W Line Through GANESHA-1 3565 sand (see Fig. 9 for location)

Target 2 - 3700

TD in Turonian Shales

High Amplitude event (not reached)

1 km (approx)

Block CY-OS/2 Seismic Lines Through Well Ganesha-1 (Previously Well Fan A-1) Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 8 Hardy 23 67 Gaffney, Cline & Associates

Well Ganesha-1: Summary of DST results

Interval Test Depth (mMD) Results Deep Fan Package DST-1 3,800 – 3,809 Max gas 0.47 MMscfd, Max cond. 2.4 bcpd, Freshwater c. 120 bpd Middle Fan Package DST-2 3,565 – 3,569 Max gas 10.7 MMscfd, Max gas 10.7 MMscfd falling to 1.47 MMscfd Middle Fan Package DST-3 3,336 – 3,341 Intermittent gas 0.1MMscfd Deep Fan Package DST-4 (in ST) 3,775 – 3,795 Fresh water 100 bpd with weak gas flow Deep Fan Package DST-4A (in ST) 3,779 -3,785 & Gas flow 0.47 MMscfd 3,805 – 3,812 plus freshwater

The water produced in DST’s 1, 4 and 4A was typically of salinity 2,500 – 2,800 mg/litre. GCA petrophysical analysis has shown that this does not correspond to the formation water.

GCA agrees with Hardy’s interpretation of hydrocarbon presence in both the Deep Fan Package (Bhuvanagiri) and in the Top Fan Package (Nannilam). GCA also supports Hardy’s oil case based upon evidence from the wellsite geology.

In the Middle Fan Package, the zone from 3,565 to 3,569 m, where the well had experienced a kick during drilling, flowed gas (DST-2) at rates which declined from a maximum of 10.7 MMscfd to 1.47 MMscfd (unstabilised). A further 5 m section, shallower in the package at 3,336-3,341 m, also yielded disappointing results (see DST-3 above). The Middle Fan Package accumulation is considered by GCA to be very limited, and of no commercial interest for the following three reasons:

a) Interpretation of the density and neutron logs revealed an isolated sand body of about 4m thickness within a shaly matrix, and thus GCA cannot confirm a gross hydrocarbon sand of more than a few metres. This is unlikely to be areally widespread, a view supported by; b) The DST-2 test, in which an initial flow of 10.7 MMscfd rapidly declined to 1.47 MMscfd, a response which would be typical of a small bounded accumulation; and c) The seismic reflection attributable to the Middle Fan Package appears extremely weak, and its expression is one of the reasons given by Hardy for reprocessing the dataset. GCA does not believe it can be mapped with any certainty.

For the Deep Fan Package, Hardy has used reservoir parameters characteristic of the area, but in its “P10” case has assumed the average absolute amplitude envelope to delimit the extent of the accumulation. GCA feels that Hardy’s pre-drill (of well Ganesha-1) and post-drill resource figures are not unreasonable, based upon the stratigraphic trap as mapped, presented in Figure 9. GCA confirms 85 MMBbl as Best Estimate STOIIP figure for the accumulation in the Deep Fan. GCA estimated Contingent Resources for the Deep Fan Package are shown in Table 6.

Hardy 68 24 Gaffney, Cline & Associates

F ig 8( a) PND-1-1 well

Ganesha-1 well Fig 8(b) Depth Structure Map at Turonian Bhuvangiri Fm.

Small 4-way dip closure

03 km

C.I. = 50m PND-1-1 well

Ganesha-1 Amplitude Map well

Area of High Amplitudes

Small 4-way dip closure in area of low amplitudes

Ganesha-1 Well 03 km

CY-OS-2

Ganesha-1 Well Area Deep Fan (Target 2)

LOCATION MAP Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 9 Hardy 25 69 Gaffney, Cline & Associates

Well Ganesha-1 has been suspended for future re-entry. At present, the exact location of the first appraisal well has not been decided.

Prospectivity

The Hardy group’s application to the DGH for extension of the permit includes proposal to drill three further wells. One would be an appraisal well to the south of well Ganesha-1, and the second an exploration well on the Shree Prospect to the east of well Fan E-1 – see below.

Ganesha-1 area prospects

Hardy believes, and GCA concur, that flow test results in the main Bhuvangiri sand have been unrepresentative. Heavy mud losses were experienced in the sidetrack of the Deep Fan Package (as well as in the Top Fan Package in the vertical hole) and the universal low fluid flow rates were attributed by Hardy to plugging and formation damage, due to the heavy mud used. The case for a further sidetrack and re-test would depend upon whether adequate cementation integrity could be achieved.

The present intent is to drill an appraisal well to delineate the Top Fan Package and the Deep Fan Package. The location to the South of Ganesha was selected to intersect the high amplitude trend present in the Top Fan Package. Assuming the same argument, this location does not seem so suitable for the Deep Fan Package, unless the well is to be sited on the closed high to the SE of Ganesha-1 (see Figure 9).

For the Top Fan Package, Hardy has adopted reservoir parameters similar to those in nearby wells, and has assumed the accumulation to extend over 100 km2 based upon average absolute seismic amplitudes. GCA believes that amplitudes not rigorously calibrated by well data cannot be used in this way. The amplitude map for the Top Fan (not shown) does not reveal anomalous amplitude at the well, which lies at the very edge of the interpreted High Amplitude envelope: the intended appraisal programme presented by Hardy to the DGH includes the necessary investigations to determine what the anomalous amplitudes portray. While an argument may be made for the predominant presence to be gas, a case may equally be made for the presence of oil, a case that GCA has accepted in terms of Prospective Resources volume. In this instance GCA has assessed the STOIIP as 220 MMBbl, and the Gross Prospective Resources as 61.6 MMBbl (using the PY- 3 Field recovery factor of 28%).

GCA estimated that the four-way dip-closed feature centred nearly 2.5 km SE of well Ganesha-1 has a Best Estimate STOIIP in excess of 25 MMBbl and a GCos of 25%.

Shree Prospect

This prospect comprises three independent objectives that can be tested by a single well. They are mapped as coincident over an area of about 2 km2 where a provisional well location has been proposed. The prospects, which lie in the Fan E area between PY-1 and PY-3 Fields, are shown on the schematic map of Figure 10 and the seismic cross-section of Figure 11,

Hardy 70 26 Gaffney, Cline & Associates

PY1 Field

Fan E-1 Well

Cretaceous Feature High Amplitude Fairway Proposed new well location

3 Target overlap area

Miocene Channel 1 outline

Basal Eocene Wedge pinchout N

05 km

Block CY-OS/2 Shree Prospect Outlines of the Three Targets Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 10 Hardy 27 71 Gaffney, Cline & Associates EOCENE A LINE 1360 CRETACEOUS Aƍ TWT msec

Lower Eocene Pinch-out Eocene top

Paleocene Top Cretaceous Feature Cretaceous Top

2 km (approx)

BBƍ

Miocene Channels LINE 1278 TWT msec

Miocene Channel 1

A Miocene Channel 2 B

Aƍ 5 km (approx) Block CY-OS/2 Bƍ Shree Prospect Seismic Lines Showing Miocene, Eocene and Cretaceous Components N Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 11 Hardy 28 72 Gaffney, Cline & Associates

which also has the well location. The Shree Prospect has components at Miocene, Eocene and Cretaceous levels.

Two parallel Miocene channels are mapped orientated approximately east- west, each extending areally to almost 10 km2. Seismically they are expressed as high-amplitude and reduced-frequency features with a chaotic seismic signature. The channels are postulated to contain biogenically sourced gas. Seismic AVO analysis has been conducted by Hardy in order to examine and confirm this; so far the results have been encouraging. Prospective Resources have been determined by Hardy: Hardy’s Best Estimate GIIP case for the more northerly channel (Channel 1) is 175 BCF, with the larger southerly channel, Channel 2, at 220 BCF. GCA endorses these estimates. The GCoS is 14%, a figure with which GCA also concurs. GCA assumed a recovery factor of 60% for its Best Estimate Prospective Resources based on the geological setting of those channels.

An Eocene stratigraphic pinch-out is illustrated in Figure 11 (though it appears better expressed on orthogonal lines). The lack of consistent reservoir sands in the Eocene/Palaeocene in the 2006 commitment well Fan E-1 (shown on Figure 10 about 4 km to the NW) is detrimental to this feature, for which there may also be serious difficulties in defining a trap. It has been suggested by Hardy that the Fan E-1 well was drilled in an inter-lobe area, between Tertiary fans, though no new structure mapping is presented and Hardy has not computed Prospective Resources in respect of this Eocene wedge.

The Cretaceous part of the Shree prospect, probably in the upper sands of the Nannilam Formation, is delineated by high amplitudes (see Figures 10 & 11) which are postulated by Hardy to indicate the sands. GCA notes that they are unlikely to represent hydrocarbons, for the bright zone extends not only beyond any area of structural closure but also would require a hydrocarbon column at least 400 m in height. Structure mapping indicates updip stratigraphic closure, assisted by a fault antithetic to the basin, while closure to the south must be entirely stratigraphic. In the east, the structural contours complete the trap but the amplitude envelope has been terminated in the east at the block boundary. The high amplitudes seem to continue east beyond this point however, as would be inferred from Figure 10 and from an arbitrary seismic line (not shown in this report) running roughly E-W across the high-amplitude feature. Based upon the area of high amplitudes, the prospective resource estimates on-block, using reservoir parameters taken from wells in the area, are 75 MMBbl STOIIP (Hardy ‘most likely’). However, the area over which hydrocarbons are present is likely to be significantly smaller, as are the Prospective Resources. Thus Hardy’s ‘most likely’ figure does not represent a Best Estimate STOIIP, which, in GCA’s opinion, is 16 MMBbl (down to the 3,520 m contour). A GCA High case estimate STOIIP is 21 MMBbl. The GCoS is estimated by GCA to be 14%; the principal risk is trap definition. A recovery factor of 28% is based on an analogy with the level of recovery obtained in the PY-3 field.

Hardy 73 29 Gaffney, Cline & Associates

GCA’s estimates of Prospective Resources are summarised below:

Prospect Gross Gas Gross Oil GCoS Prospective Prospective % Resources Resources Best Estimate Best Estimate BCF MMBbl Ganesha-1 Top Fan 61.6 25

SE Four-Way Closure - 7.0 25 Shree Miocene 105 - 14 Channel 1 Shree Miocene 132 - 14 Channel 2 Shree - Cretaceous - 4.5 14

In addition, there are smaller high-risk Leads within the acreage (for example those designated TRL Nannilam Sand, TRL Deep Cretaceous, PY Updip), but no resource volumes have been attributed to these. However, there was a mention of the potential prospectivity of the southern Tranquebar sub-basin area in Hardy’s application to the DGH to extend the licence.

1.2 Bombay Basin (sometimes Mumbai Offshore Basin)

The Bombay Basin extends over 145,000 km2. The basin is bounded at the east by volcanic lava flows known as the Deccan Trap, in the south by the E-W- trending Pre-Cambrian Panjim Ridge, and in the north by the Saurashtra Peninsular: to the northeast it continues into the onshore Cambay Basin. The basin can be divided into four tectonic units, the most prominent being the Bombay High, characterised by NNW-SSE horst and graben systems, developed during the Palaeogene. Block GS-01 in which Hardy has a working interest, lies in an extensive clastic sub-basin fringing the Bombay-Ratnagiri Shelf to its west. These clastics were deposited in the Palaeogene and Miocene.

The lithostratigraphy is determined by basalt lavas which overlie crystalline basement. In deeper areas there can exist Upper Cretaceous sediments beneath the Deccan Trap, though more widely the basalts are overlain by continental and estuarine clastic sediments of the Upper Palaeocene to Lower Eocene (Panna) formations. Further to the west, shale has been deposited. 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 of carbonate origin in the central and southern basin part – in the north and west it is fine clastic. From Upper Eocene to Middle Miocene a shallow water environment predominated, with deltas and lagoons. The Tarapur Fm, Middle Miocene to Recent was deposited over the entire basin as a single shale interval (see lithostratigraphic section, Figure 12). The thickness of basin fill can exceed 8,000 m.

Major oilfields such as Bombay High, Mukta, Heera, Ratna and others produce from Lower and Middle Miocene limestones. These are wackestones,

Hardy 74 30 Gaffney, Cline & Associates

FORMATION LITHOLOGY AGE OBJECTIVES

Miocene to Clay (soft,plastic), Shale Tarapur Recent

Predominantly claystone & silts

Secondary Target-I Saurashtra Mid -Top of Reef 3 Limestone with minor Miocene shale/marlstone Primary Target - I -Lr. Miocene Limestone Bombay- Lower Ratnagiri Miocene

Alibag Primary Target - II -Ur. Oligocene Limestone

Oligocene Heera/Mahum

Secondary Target-II - Bassein Limestone Bassein Mid Limestone with minor Eocene shale/marlstone

Secondary Target-III - Panna Limestone Limestone with minor shale/marlstone Panna Early Eocene

Late Paleocene Trap wash: Weathered basalt & minor shale/siltstone Deccan Trap Up. Cretaceous (?) Volcanics:Basalt

Basement Pre Cambrian

ClaystoneClaystone LimestoneLimestone SandstoneSandstone TrapwashTrapTrapwash wash VolcanicsVolcanicsSiltstone Siltstone

MarlstoneMarlstone Shaly Limestone Intrusives/ Metamorphics

Bombay Basin Lithostratigraphic Column

Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 12 Hardy 31 75 Gaffney, Cline & Associates deposited in a lagoonal setting. The main source rocks are the Palaeogene and Miocene pro-delta muds deposited in major low areas in the basin, the main such ‘kitchen’ being the Dahanu Depression, extending for around 500 km parallel to the present-day coastline east of the Bombay High. There is also a source area west of the High, underlying the Hardy block. Here the source horizons below 3,500 m are overmature and mainly gas-prone. There are no carrier beds, and the (proximal) source needs to be connected to the reservoirs by either faulting or 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).

1.2.1 Block GS-01 (Hardy NWI 10%)

Block GS-01 is located in the Bombay Basin off the west coast of India: it lies 220 km west of Bombay and 60 km south of the Saurashtra Peninsular. The Bombay High oilfield lies 40 km east of the eastern boundary of the block (see Figure 13). This 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 gasfields of Bassein, South Bassein, Mid Tapti and South Tapti. The majority of the 600 exploration and appraisal wells that have been drilled in the Basin have tested the section down to the Deccan Trap or Precambrian granitic basement (see above).

The block is operated by Reliance (Reliance International Limited) whose working interest is 90%. It encompasses 8,841 km2, and water depths vary from 50 to 90 m. The exploration concession (PEL) was awarded on 16th August, 2001 under NELP II terms, comprising:

x Three exploration phases, each not exceeding three years, for a total period of seven years; x A Phase-1 work programme of:

a) Seismic data acquisition (1,200 km 2D plus 1,020 km2 3D), processing, re-processing (3,030 km 2D) and interpretation. This commitment has been completed, with the acquisition of 2,363 km 2D, 1,711 km2 3D, and reprocessing of 4,391 km 2D; and b) A drilling programme of 5 exploration wells; to-date, two wells have been drilled, and three remain.

x A PSC allowing for Cost Recovery and Profit Oil sharing (signed 17th July, 2001).

The block has been extensively covered by gravity, magnetic and seismic surveys. Approximately 12,000 km of 2D seismic (over 600 lines, of which 50, totalling 2,363 km, by Reliance/Hardy) have been acquired, processed and interpreted. A 3D survey of 1,216 km2 was gathered over the east- central part of the block in 2005. A further 3D survey of 1,000 km2 is scheduled for later in 2007. 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. However, B-107-1 well, drilled by ONGC in 1990, is reported to have oil shows.

Hardy 76 32 Gaffney, Cline & Associates

To Hazira

DIU MID. TAPTI Gujerat-Saurashtra Basin S. TAPTI C23

C24

36" 42"

GS-01 FD C D

S F

M C

MS 0M 0 M 7 0 6 0 BOMBAY 1 MUKTA HIGH PANNA

35 0 M M BASSEIN S CFD Mumbai 26" 30" BASSEIN S.

Bombay Basin

CFD MS 0 M 21 Uran 26" Terminal HEERA Arabian Sea

istan China RATNA

Pakistan Nepal Bhutan LEGEND 0255075100 Km Bangladesh Oil Field

Myanmar Gas Field

IndiaIndia Sub-sea Gas Pipeline (Existing) Sub-sea Oil Pipeline (Existing) n Basin Limits B a y o f B e n g a l GS-01 Block Location Andaman Sea

Sri Lanka Source: GCA/Petroview Proj. E1741.01 Jan 08 Checked: Fig. 13 Hardy 33 77 Gaffney, Cline & Associates

Of the original Phase-1 work programme part a) has been completed, and two of the five commitment wells have been drilled. Phase-1 was initially extended two years to August, 2006, and more recently a further extension of 22 months was granted, extending to July, 2008.

It is intended that all five commitment wells will be drilled in the area covered by the initial 3D survey. This is shown on the seismic depth structure map of Figure 14, which also shows the locations of wells GS-01-A1, GS-01-B1 and three further, provisional, well locations – GS-01-B2, -Prn1 and –S1.

Well GS-01-A1

All the five main targets of GS-01-A1 well proved tight (low permeability). High gas saturations occurred in a basal sandstone of <15 m net thickness, but flow testing was not possible due to limitations of the drilling rig.

Well GS-01-A1 spudded on 9th February, 2006 in 83 m of water. It terminated in Deccan Trap volcanics, at a depth of 4,374 m. The well had five targets at Middle and Early Miocene (reef), Oligocene (reef) and Middle and Early Eocene ages – see Figure 12. At two points in the Mid Eocene Bassein limestone, 3,622 m MD and 3,723 m MD, gas shows were recorded, but all the main targets proved tight. At 4,298 m MD formation gas went up to 35%.

This was beneath the Early Eocene Panna limestone, in a basal sandstone of up to 15 m net thickness (not a designated target when the well spudded) overlying the basement. At this point the well was about 305 m deep to prognosis because of a higher overburden velocity than expected, so that at total depth the well was within HP/HT conditions and close to the limits of the capacity of the rig. Thus testing of the gas sand was not possible, and the well was suspended.

Mapping at Top Panna limestone shows a very well developed four-way dip closure with a relief of more than 100 m; at Top Basement, a smaller four-way dip closure of over 60 m was mapped immediately beneath, so that, minimally, a structurally limited drape feature exists. No gas/liquid contact was intersected in the well. However, as seen from Figure 15, downdip of the discovery, the reflector representing the “Top Basal Sand” brightens notably. Analysis of the A1 well results is at an early stage, for as yet no mapping on Top Basal Sand has been presented to GCA, and AVO studies aimed at confirming the presence of gas stratigraphically trapped independently of the structural closure have not yet been made available to Hardy. No post-drilling resource estimates are deemed to be appropriate in this instance.

Discovery Well GS-01-B1

The well spudded on 2nd March, 2007, 240 km northwest of Mumbai in 79 m of water. It terminated in Lower Miocene reefal carbonates at a depth of 2,282 m MD (2,256 m TVDSS). The well had multiple limestone targets, including Middle and Lower Miocene, Upper Oligocene, Middle Eocene (Bassein Fm) and Lower Eocene (Panna Fm). The location is shown on the map of Figure 14 and the seismic line, Figure 15. The well terminated prematurely in the Lower Miocene because of mud losses/lost circulation, having encountered gas and condensate in Middle Miocene limestones

Hardy 78 34 Gaffney, Cline & Associates

) B1 (a 16 g Fi B2

) (b 16 g Fi

Prn1

Possible arcuate trend A1 of reefal build up

010 Km C.I. = 20m

LEGEND

-3550 Depth Contour (metres subsea) GS-01 3D area Gas/Condensate Discovery Depth Structure Map at Gas Shows Top Bassein Formation Proposed Well Location Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 14 Hardy 35 79 Gaffney, Cline & Associates

NNE SSW

Well B-1 Well A-1

Secondary source kitchen Reefal Build-ups Basal clastics Main source kitchen

10 km (approx)

Block GS-01 Seismic Line Through the B-1 and A-1 Locations Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 15 Hardy 36 80 Gaffney, Cline & Associates

before entering reefal material of high vuggy porosity and permeability. 24 m of perforations were opened within the Middle Miocene limestone 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.

The operator, Reliance, officially notified the government of a discovery named Dhirubai 33, on 14th May, 2007. It is the most westerly discovery in India to date.

Levels of hydrogen sulphide between 1,700 and 3,800 ppm, and CO2 up to 7% were noted in the produced gas. An estimate by Reliance of Contingent Resources for the tested zone is presented in Table 5. The structure at the H1A level (Top Middle Miocene) is a four-way dip-closed anticline. The 1C, 2C and 3C estimates of gross GIIP are 50, 150 and 570 BCF respectively. Based on the available information GCA was unable to validate these estimates.

Future Prospectivity – B1, B2, S1, Prn1

The reef penetrated in the bottom of well B1 was a predicted primary target. As stated above, on entering the reef, mud losses at a rate of 1,000 bpd were recorded. A test was attempted within the reef, but this failed, possibly because of earlier efforts to stem the mud losses with cement. The other main target, the Upper Oligocene limestone was never reached. Prospective Resources for the undrilled deeper objectives for B1 and B2 prospects are listed in the table below.

Following the encouraging result in the B1 well, it is intended that the B2 well will become the next location, rather than A2, which was to have been a downdip appraisal of A1, seeking thicker, better-quality sands. From Figure 16 it appears that well B1 and locations B2 and S1 lie on an arcuate trend of outer shelf carbonate build-ups independently sealed by lagoonal facies. The seismic at both the B2 and S1 locations appears almost identical to that at B1, respectively about 4 km and 20 km distant to the southwest, on the same barrier reef trend. Given that the proven petroleum system is the same, the wells should now have a reasonable chance of success (see Table 7). Both locations are illustrated in Figure 14.

At location Prn1, a little over 10 km northeast of well A1, the seismic expression appeared similar to the latter, with a high-amplitude reflector downdip of a minor drape, or perhaps shelf margin feature. In the light of the result at well A1, where all the targets proved barren, this is seen as a less attractive prospect than either B2 or S1, and GCoS is assessed as no more than 10%.

Following the discovery of gas in GS-01-B1, and the gas shows in well GS- 01-A1, GCA has computed the ‘gas case’ for all the above prospects except the Middle Miocene (where the figures were recently supplied by Reliance). GCA adapted the GIIP estimates as tabulated below. The Estimated Prospective Resources are shown in Table 7. The gas in the GS-01 B1 discovery was very lean, a fact which, together with the over-mature local source environment leads GCA to favour the gas case for the undrilled prospects also.

Hardy 81 37 Gaffney, Cline & Associates Well GS-01-B2 SWSW NENE

Top Mid. Miocene

(a) Proposed well GS-B2 TWT msec on the trace 5939

Top Mid. Eocene (Bassein)

Top Panna

Deccan Trap

Well GS-01-S1 2 km SWSW NENE (approx)

Top Mid. Miocene

Top Mid. Eocene

TWT msec (b) Proposed well GS-S1 on the trace 6765

Source: Hardy

Block GS-01 Prospects B2 and S1 2 km (approx) Proj. E1741.01 Jan 08 Checked: Fig. 16 Hardy 38 82 Gaffney, Cline & Associates

GS-01 PROSPECTS - SUMMARY OF GIIP (BCF)

Prospect Reservoir Low Best High GCoS Estimate Estimate Estimate (%) B2 Middle Miocene** 50 170 610 30 B1/B2 Oligocene 15 26 47 30 Bassein 45 82 171 30 S1 Middle Miocene** 78 205 665 30 Lower Miocene 18 33 63 30 Oligocene 14 23 43 30 Bassein 22 43 89 30 Panna 6 12 26 30 Prn1 Oligocene 18 33 76 10 Bassein 26 57 120 10

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. ** indicates Reliance estimates 11/07/2007. The remaining Reliance values have been suitably adjusted by GCA.

1.3 Krishna Godavari Basin

This basin is located in the central part of the eastern passive continental margin of India. It covers an area of about 45,000 km2, approximately 50% of which lies onshore. The structural grain of the basin is northeast-southwest, and it extends southeast into the deep water of the Bay of Bengal. The two blocks with Hardy working interests, D3 and D9 are in the deep water.

Rifting commenced in the Permian, with Permian, Triassic and Jurassic sediments, mainly sandstones, being deposited in the rift valley and in topographic lows. Subsequently this sequence was overlain by a Lower Cretaceous transgressive sedimentary wedge. Since the Cretaceous, Krishna-Godavari has become a pericratonic basin. The southeastern part of the basin became a major Tertiary depositional centre because of basinward faulting (associated with reactivation of NE-SW-trending Precambrian lineaments) during the early Palaeocene. Significant delta progradation did not occur in the area during the Palaeocene and early Eocene; rapid sediment fill in the low has facilitated smooth progradation of the delta towards the southeast since the middle Eocene.

In the present day deep water sector, sandstones within Lower and Upper Cretaceous source shale beds have proved to be reservoirs for both oil and gas, as have Lower Eocene sandstones that overlie Palaeocene source beds. The main reservoir section is the Ravva Sandstone of Miocene-Pliocene age. In addition to the Cretaceous and Palaeocene source rocks mentioned, there are Lower Eocene shales with TOC of up to 4%, which are gas-prone and have generated hydrocarbons since 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.

Hardy 83 39 Gaffney, Cline & Associates

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, including erosional channels, updip pinchouts, unconformities and permeability barriers are of primary importance. The shale-dominated section (see the lithostratigraphic column of Figure 17) provides copious sealing capability, though a thick middle Eocene carbonate may also provide a regional seal for Cretaceous and Lower Eocene reservoirs.

1.3.1 Block D9 (Hardy NWI 10%)

Almost this entire undrilled block is located in the Krishna-Godavari Deepwater Basin’, off the east coast of India (see Figure 18). The northwest corner of the concession is little more than 20 km from the Dhirubai complex of substantial gas discoveries made by Reliance in recent years, and due to come on stream in 2009.

D9 is also operated by Reliance, which has a 90% working interest. The block has an areal extent of 11,605 km2, and water depth varies from 2,300 m in the northwest to 3,100 m in the southeast. The Exploration Licence was awarded on 2nd April, 2003 under the NELP III terms, as follows:

x Three exploration phases, the first not to exceed four years, the second and third not to exceed 2 years each, for a total period of eight years; x Phase-1 work programme of:

a) Seismic data acquisition (1,650 km2 of 3D seismic plus 2,100 km of 2D), processing, re-processing (500 km 2D) and interpretation. This was completed by December, 2004; and b) A drilling programme of 4 exploration wells. The first well has been delayed until later this year because of the shortage of deep water drilling rigs.

x PSC signed on 4th February, 2003, allowing for Cost Recovery and Profit Oil sharing.

In addition to the obligation programme, the group has carried-out hydrocarbon seep studies, seabed coring, an electromagnetic survey, gravity & magnetic modelling, and basin modelling.

Based upon an irregular reconnaissance 2D seismic grid, leads at Upper Miocene, Middle Miocene and Oligocene were identified. These leads are areally large structural closures toward the northwest corner of the concession, for which GIIP of many TCF has been computed by Reliance. A fourth lead is a Pleistocene channel in the south eastern part of the block with a computed Reliance GIIP of a similar order of magnitude. New mapping by Reliance, based upon the 3D and recent 2D seismic (an example map is shown as Figure 19 on Top Miocene), now exists but no revision of these GIIP estimates is available. The large closures mapped with the reconnaissance grid are broadly endorsed by the new data.

Hardy 84 40 Gaffney, Cline & Associates

Principal Regional Age Formation Lithology Thickness (m) Sedimentary Cycle tectonic events

Godavari Holocene Clay (Seal) > 2000 (S Pleistocene a Regression n R d a v re v s a Pliocene e rv o i rs ) Collision of Miocene Indian and > 1200 Tibetan Plates Transgression Oligocene Regression

Eocene Vadaparu Transgression Collision of Shale Indian and (Source & Seal) > 2500 Eurasian Plates Regression Palaeocene Transgression

Blocks D9/D3 Post-Mesozoic Stratigraphy

Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 17 Hardy 41 85 Gaffney, Cline & Associates

Krishna-Godavari Basin D9

0 100 km

istan China LEGEND Hardy Block Interests Pakistan Nepal Bhutan Oil Field Bangladesh Gas Field Gas Condensate Field Myanmar Basin Limits IndiaIndia

n B a y o f Location Map Showing B e n g a l Andaman D3 and D9 Licences Sea

Sri Lanka Source: GCA/Petroview Proj. E1741.01 Jan 08 Checked: Fig. 18 Hardy 42 86 Gaffney, Cline & Associates

L IN E 2 6 2 9

LINE 2629

4500

0 10 km

C.I. = 100m TWT msec

Bright Spots 2 km 5000 (approx) Examples of Amplitude Anomalies Within D9

Block D9 Depth Map on Top Miocene

Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 19 Hardy 43 87 Gaffney, Cline & Associates

The GIIP figures carried by Hardy are a slight modification of the original 2004 Reliance numbers (Prospective Resources have been derived by applying a recovery factor of 0.7):

D9 GIIP and Prospective Resources Summary (TCF)

Lead GIIP Gross Gas GCoS (%) Prospective Resources Best Estimate Upper Miocene 18 13 15 Middle Miocene 27 19 15 Oligocene 19 13 15 Notes: 1. Data source, Reliance 2004. 2. Adoption of such techniques as AVO and seabed logging, calibrated against the responses across discoveries in neighbouring blocks may increase the GCoS 3. GCA did not assess the Pleistocene lead due to insufficient data.

The Prospective Resources volume estimates of 2004 are considered by GCA to be of low confidence level. However, GCA recognises that, since the time of the 2004 estimates, new 3-D seismic was acquired and interpreted to mature these leads into prospects. The latest volumetric estimates of Reliance and Hardy were not available to GCA at the Effective Date of this report.

Initial exploration will be focused upon amplitude anomalies within closure in the Miocene and Pliocene, rather than upon gross structural features. There appear to be many such seismic anomalies (two examples are shown in the inset of Figure 19) and, given its proximity to D6, exploration of the large block is regarded with considerable optimism.

1.3.2 Block D3 (Hardy NWI 10%)

This Block is located in the Krishna-Godavari offshore basin, southwest of the Ravva (operated by Cairn) and G1 (ONGC) oilfields, and due south of the ONGC oilfields of G15 and G23 as shown in Figure 18.

D3 is operated by Reliance, which has a 90% working interest. This block measures 3,288 km2 in area, with water-depths varying across the block from northwest to southeast between 400 m and 2,100 m. The exploration concession was issued on 5th December, 2005 under the NELP V terms, as follows:

x three exploration phases, the first not to exceed four years, the second three years and third one year, for a total period of eight years; x a Phase-1 work programme of:

a) 2,100 km2 3D seismic data acquisition and processing, 1,020 km 2D re-processing, and interpretation. At present the acquisition of 1,930 km2 of 3D is in progress, and a further 1,150 km2 is planned;

Hardy 88 44 Gaffney, Cline & Associates

b) A drilling programme of 6 exploration wells. This programme should start in 2008.

x A PSC signed on 23rd September, 2005, allowing for Cost Recovery and Profit Oil sharing.

The block is undrilled, but is covered almost entirely by 2D seismic lines spaced roughly 1 km x 2.5 km. All these data, amounting to over 5,000 km, are now in the possession of the group, and form the basis for the existing preliminary interpretation performed by Reliance. Of the above work programme, the reprocessing of 450 km2 of existing 3D seismic (about half of which lies within D3) by Western Geco is completed and has been delivered. The first of two 3D surveys is currently in progress – this will cover approximately 1,930 km2, most of the western portion of the acreage. On completion, these data will be processed through a sequence including pre- stack depth migration (PSDM), so that no data for interpretation should be expected this year. In addition, other studies (geochemical sea-bed coring, multibeam survey, heat-flow study, basin modelling) have been carried-out. No drilling is planned before 2008.

Exploration in this block will initially be driven by seismic amplitude work. Fourteen features (KGD-1 to KGD-14) based upon amplitude anomalies have so far been identified, five of which have been determined from the original 3D (gathered by Cairn), and are thus confined to a very limited area. Some of these, KGD-2 and -3 for example, are clearly seen to define sinuous channels. GCA has sufficient data to validate the five prospects, GIIP values for which are listed below. Figure 20 shows prospect KGD-1, a well defined seismic anomaly within the Upper/Middle Miocene.

D3 GIIP Summary – Reliance (operator) Best Estimate figures (BCF)

Prospect Horizon GIIP KGD-1 Upper/Middle Miocene 407 KGD-2 Middle Miocene 833 KGD-3 Middle Miocene 811 KGD-11 Miocene 1,048 KGD-12 Eocene 197

The reservoir parameters adopted by Reliance in computing the above are in line with those of nearby wells for which data are published. However, in these wells, reservoir thicknesses average around 25% of the values used by Reliance; further, the areas used by Reliance, in GCA’s opinion, generally represent maximum cases. GCA’s GIIP estimates – at this stage of evaluation - are as listed below:

D3 GIIP Summary (BCF)

Prospect Horizon GIIP KGD-1 Upper/Middle Miocene 102 KGD-2 Middle Miocene 162 KGD-3 Middle Miocene 94 KGD-11 Miocene 204 KGD-12 Eocene 25

Hardy 89 45 Gaffney, Cline & Associates

Upper Miocene

Within Mid Miocene-II

Within M Miocene 1 M.Mio.UC Lower Miocene 3D seismic line 620 TWT msec Eocene UC Paleocene

Cretaceous

2 km (approx)

Approximate Location of 3D Line 620

Amplitude

Block D3 Seismic Expression of Prospect KGD-1

Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 20 Hardy 46 90 Gaffney, Cline & Associates

GCA estimated Prospective Resources are shown in Table 7. GCA has seen no mapping relating to the other nine leads, and thus cannot comment on the volumes computed for these.

Reliance has produced structure maps at Cretaceous, Palaeocene and Plio- Pleistocene levels. Top Palaeocene includes a large four-way dip closure with a relief of 150 m; however, the lithology is thought to be shale (Palakollu Shale Fm), and the maps may have relatively little prospective significance.

GCA notes Block D3 is more favourably sited in the basin with respect to existing discoveries than D9 (as shown in Figure 18), and also that, as 5 prospects exist in the small area encompassed by the on-block 3D, the potential for the remainder of the block appears most encouraging.

Hardy 91 47 Gaffney, Cline & Associates

2. NIGERIA

Hardy is the Foreign Technical Partner in two concessions awarded in the Marginal Fields Round in 2003. The blocks are both onshore in the Niger Delta Basin. As can be seen from the location map (Figure 2), the Atala block lies in the extreme southwest of the onshore delta in the Coastal Swamp Depobelt. The Atala- 1 wellsite is in the swamp and a barge was required for operations. Figure 2 also shows the Oza Field which is on flat dry country very close to the main road to Port Harcourt, the capital of Rivers State, some 33 km west-southwest.

The security difficulties associated with working in Nigeria are well publicised. At the Oza Field the pipelines have been illicitly removed and trucking oil a few kilometres to the nearest Shell flow station has been rejected by Shell as too dangerous. So far however, operations at the Oza location have not encountered local opposition. Atala lies in the swamp area, where local militancy is more pronounced; whether the intended operations will be impeded will not be known until the swamp barge moves onto location, an event intended for around end 2007.

2.1 Niger Delta Basin

The Niger Delta Basin is a Tertiary delta located on a marginal sag basin. Onshore and offshore its extent is about 75,000 km2, and sediment fill can attain a thickness of 12 km. It is one of the world’s most prolific deltaic hydrocarbon provinces, hosting postulated resources in excess of 23 BBbl liquids and 124 TCF gas, in rocks of Palaeocene to Pliocene age. Three petroleum systems are present in the Niger Delta, two of which, the Tertiary (deltaic) system and the Upper Cretaceous (lacustrine)-Lower Palaeocene (marine) system extend over both the blocks with Hardy working interests. The Tertiary is the more important.

The Tertiary delta has been growing from Palaeocene times to the present. At the base are mainly marine shales with some turbidite units, on which a predominantly regressive sequence was deposited with an alternation of paralic sandstones and shales overlain by continental sandstones. The delta is characterised by typical topset, bottomset and foreset beds prograding seaward. Distinct facies of prodelta (Akata formation, Eocene to Miocene), delta-front (Agbada Formation, Miocene-Pliocene) and delta-top (Benin Formation, Pliocene- Pleistocene), are developed, with both marine and non-marine clastics present. Agbada sands, interfingering with Akata shale source beds are the most significant hydrocarbon reservoirs, though the source beds contain turbidite sand reservoir bodies also (Figure 21), and these produce in the offshore delta.

A predominance of NW-SE and NE-SW structural lineaments confirms the influence of deformation of the basement, which also displays these trends, in the subsequent structuration. In particular, the Oligocene and early Miocene depocentres correspond to the low areas between Basement blocks The structural style of the Niger Delta sedimentary basin can readily be seen from Figure 22, which is a 2D seismic dip line dating from 1970 across the Oza Field. Growth faults, very common in the Niger Delta, are present. The relative rates of subsidence and of deposition determine whether antithetic faults are set up, and thus whether collapse crest anticlines, frequently associated with multiple hydrocarbon traps occur. Akata shales source the interfingered sands using the growth faults as conduits. It is thought that hydrocarbon generation was a function of depth of burial for each separate structural megaunit, while migration and accumulation occurred up to present day. Gas tends to predominate in the deeper structures.

Hardy 92 48 Gaffney, Cline & Associates

Oza Reservoirs K, L, M Series

M5.0

Atala Reservoirs U1.0 to U7.0

Source Beds

Sand

Niger Delta Basin Shale Lithostratigraphic Column

Source: GCA Proj. E1741.01 Jan 08 Checked: Fig. 21 Hardy 49 93 Gaffney, Cline & Associates

Oza Field

Pleistocene

L3 Pliocene

Upper Miocene M5 TWT msec

GCA Adjusted to Agree with Map

5 km (approx)

Seismic 2D Dip Line 11-70-1-145 Across Oza Field

Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 22 Hardy 50 94 Gaffney, Cline & Associates

Reservoirs are not usually filled to their structural spill-points. The spill point of a reservoir within a typical fault terrace tends to be determined by its intersection with the fault, and considerations relating to fault-seal. Shell statistics from 1971 revealed that more than 70% of oil reservoirs possessed oil-column heights of less than 15 m, while only 5% were greater than 45 m.

2.1.1 Oza Field

The Oza Field is located in the northwestern part of block OML 11 in Rivers State. Millenium Oil & Gas Company Limited (Millenium) is the operator with a 60% interest, and Hardy is the designated Foreign Technical Partner (40%). The concession has been acquired as a farmout from Shell Petroleum Development Company of Nigeria Ltd (SPDC), is 22.9 km2 in extent, and entitlement of the farminee is restricted to a depth of 3,291 m TVDSS. The agreement covers an initial 5 year period from 27th April, 2004, and may be extended with approval from DPR.

Oza Field was discovered by Shell with well Oza-1 in 1959: Oza-1, a vertical hole, reached a total depth of 3,279 m MD in Upper Miocene sands of the Agbada Formation (see Figure 21). The well encountered hydrocarbons in at least nine sand bodies between 1,824 m and 2,926 m. All pay sands in Oza are typically unconsolidated paralic or fluviatile sands occurring in the Agbada Formation, and can be correlated between all four wells drilled.

Wells Oza-2 (TD 3,353 m MD, a vertical hole) and -3 (TD 3,017 m MD, 2,979 m TVD deviated more than 229 m approximately southeast) were drilled to delineate the field during 1962-64. Oza-4 (3,228 m MD, c.3,158 m TVD) was sidetracked about 290 m east-northeast from Oza-3, where the main pay sand (M5.0 in Shell nomenclature) was found to be cut by a fault which condensed the section by about 43 m (see Figure 23 for well locations). In addition to the M5.0, five further pay zones have been identified in the Oza field on logs over a range of depth from above 1,829 m to 3,048 m. The study of the Oza logs have indicated shallower sands, particularly in well no. 1 (L2.6, L2.2 and L2.4A) which appear to be HC bearing and which have not been flow tested in any of the wells so far. Both Oza-1 and Oza- 4 are single completions and can be dually completed to concurrently open up additional zones.

From the above wells, three reservoirs, M5 (in Oza-1 & Oza-4), L9 and M2.1 (in Oza-2) were completed for production. Other resources were never produced because of their thin oil columns and risk of coning from the water contacts. The field was put on production in 1962 and produced intermittently until finally being closed in 1982-83 in view of high GOR/water cut and pressure depletion. GOR’s in well Oza-1 showed severe variations during production (800-10,000 scf/stb) which could be in part due to faulty measurements, and were considered unreliable – as were GOR’s in well Oza- 2. In well Oza-4, GOR increased from 1,600 to 7,600 scf/stb within 6 months of commencement of production, which could reflect a restricted reservoir with initial pressure close to saturation pressure.

Cumulative production for the field by March, 1983 was 1 MMBbl of oil, 0.059 MMBbl of water and 2.46 BCF. Production was mostly from the discovery well. The production mechanism is thought to be a combination of water drive, gas cap drive and depletion drive. Oza production was through

Hardy 95 51 Gaffney, Cline & Associates Fig 22

4 144 145 735

744

2 3

021 km

C.I. = 100ft

LEGEND Field 2 Well Locations

-9500 Depth Contour (ft) Fault Oza Field Seismic Lines Depth to Top M5 Sand (Shell Nomenclature) Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 23 Hardy 52 96 Gaffney, Cline & Associates

Oza flow station (which has since been dismantled) through a connecting manifold into the Imo River-Afam pipeline which ran to the Imo River flow station. Both flow stations were situated on SPDC’s major oil pipeline that passes southwards to Bonny Terminal through Korokoro, Bomu and other fields.

Based on the production history, Oza seems to contain volatile fluids with an average API gravity of 37o, which yield high GOR’s when produced under depletion drive mechanism. The water underlying some of the zones in Oza field could be a concern if the pressure drawdowns from wells are excessive. With modern methods of lateral drilling the risk of water coning might be reduced. Oza’s overall performance interpretation is subjective and the analysis of its future potential will improve once the relevant information become available. The JV has put in place a program to obtain the critical data. This includes reservoir characterization parameters, core analysis, fluid analysis, well test, and PVT data.

Presently available mapping of the field by Shell dated June, 1991 consists of a single depth map on the top of the productive M5.0 sand, shown as Figure 23. The map is based upon the four wells plus only five 2D seismic lines plotted in approximate positions on the map. The migrated seismic data were acquired in 1970 and 1988. An example dip line is shown as Figure 22. Since Millenium/Hardy acquired the concession, a 3D seismic survey has been shot by Shell, which includes the Oza area, and the Millenium group has been negotiating to purchase data from this survey.

The mapping shows the field (Figure 23), at the M5.0 level, to lie in a terrace between two normal, south-hading growth-faults regionally aligned NNW-SSE. In the north, the field is closed by the structural contours: to the south, closure is affected by a south-hading fault running roughly east-west. However, this fault does not appear on either the interpreted line 11-70-1-144 or the adjacent line 11-70-1-145, and may have been inferred by Shell from field data and surface expression – perhaps a river bed. Whatever its shortcomings, and they are not inconsiderable, this is the only credible mapping available to GCA, and from it may be derived a hydrocarbon volume for the M5.0 horizon. Adopting accepted parameters for phi (25%), Sh (75%), Bo (1.6) and a net oil sand of 9.75m yields an in-place volume of 11.6 MMBbl for the M5.0 sand. This coincides with the deterministic figure provided by Millenium, and which may have been derived originally from Shell – though this is not certain. This provides some confidence in the Shell values for the entire field.

3D seismic mapping will delineate more accurately the field and facilitate positioning of any new wells or new completions. In 1959 the Shell ‘P50’ STOIIP was about 27 MMBbl, so that recovery prior to shut-in was little more than 3%. Re-perforating the existing wells and placing them on production is unlikely to achieve much improvement. On the other hand, planned horizontal completions in the upper zones of the productive reservoirs should reduce the chance of water ingress and pressure drawdown/raised GOR. For a new development, a Recovery Factor in excess of 30% would be anticipated, based upon modern drilling practice in the onshore Niger Delta.

Hardy’s June, 2007 proposed field development plan envisages a three phase development. Phase I starts in 2007 and intends that each of Oza-1,2, and 4 is checked for its integrity and tested through the existing perforated

Hardy 97 53 Gaffney, Cline & Associates

interval, or alternatively a new interval (depending on test results). In parallel, it incorporates putting in a connection pipeline to a nearby SPDC flowstation, most likely Isimiri.

Phases II and III will depend on results from Phase I. Phase II also starts in 2007 and comprises re-opening the old wells and the development of the geological and reservoir model for Oza. Phase III will commence in 2008 and envisages work-overs of existing wells for additional completions and drilling of new wells.

GCA considers the resources as at 30th June, 2007 in Oza to be Contingent Resources/Development Pending which is the highest level towards commerciality in this category. This is because the data available at this stage are insufficient to clearly assess Oza’s commerciality with reasonable certainty. Hardy’s commitment to re-develop and produce Oza is pending finalization of the crude handling agreement, the support from Shell with respect to the crude transport and the use of its facilities, the finalization of the gas processing agreement and the extension of the agreement once the initial term expires in 2009. GCA, however, has confidence that Oza’s Contingent Resources will move to the Reserve category in the very near future once the above are secured. GCA reviewed each of Oza’s well production performances versus their proposed re-entry programme. Based on indications from some static pressure measurements and general field engineering experience, GCA assumes that the reservoir pressure at Oza has built up to allow the field to be put back on production. GCA incorporated historical production performance parameters with Hardy’s proposed development programme for its estimation of Oza’s Contingent Resources. GCA’s estimated Contingent Resources for Oza are reported on Table 6.

2.1.2 Atala Concession

The concession is situated in mangrove swamp in the coastal areas of northwestern Bayelsa State of Nigeria in OML 46 (see Figure 2). In 2003, Atala was awarded as a marginal field to Bayelsa Oil Company (BOCL), as operator, while Hardy was designated Foreign Technical Partner with 20% working interest. The arrangement by which the licence is held is a farm-out from SPDC Nigeria: the farm-out area is 34 km2 and the farm-out depth is restricted to 3,795 mSS. The agreement covers an initial 5 year period from 27th April, 2004, and may be extended with approval from DPR.

The only well, Atala-1, a deviated hole, sidetracked a distance of 1,150 m to the SW at TD for mechanical reasons, was drilled in 1982 to a total depth of 4,058 m MD (3,816 m TVDSS). It is located 6 km inland from the coast, about 7 km south-east of its junction with the Dodo River. There is a large complex of about a dozen major fields close by, to the north and northwest. Atala was originally defined as a small domal feature by 2D seismic. The well encountered 25 m of oil and 108 m of gas in 9 sand intervals within the Oligo- Miocene Agbada Formation (oil in U1, U2 & U4; both oil & gas in U3 and U7: gas in U5, U6, possible gas in U5.5 & U6.5) between 2,140 mSS and 3,289 mSS. In addition, Shell lists the deeper F9.6 as an (unspecified) hydrocarbon-bearing reservoir. These Agbada Formation sand beds (see Figure 21) are unconsolidated and moderately consolidated paralic sands, typically delta bars and nearshore fluvial deposits. The estimated porosity range is 25-31%. At the time of drilling, gas was not required in Nigeria and

Hardy 98 54 Gaffney, Cline & Associates

Atala-1 was considered uncommercial as an oil field (2.3 MMBbl recoverable oil), consequently the well was suspended.

Atala, for which no sample data are available, seems to contain volatile liquids of API gravity estimated in the range from 39 to 44o API, which would demonstrate high GOR’s when produced under natural depletion drive. In some of the thinner zones, such as U1, U3 and U4 water coning could occur. There is a good deal of uncertainty surrounding Atala, partly because the well was not flow-tested, but also because much of the basic data was either never gathered or is now lost. This includes reservoir characterization parameters, core analysis, fluid analysis, well tests, and PVT data as well as field related parameters such as the integrity of the existing well, geological and geophysical characteristics and volumetric properties.

Though the well at Atala was drilled on the basis of 2D seismic, the most recent mapping, performed by Eogas (a Lagos-based consultancy), for BOCL during 2006 used 3D acquired by Shell in 1999. An area of 98.44 km2 fully migrated was given to the new licensees. This area is just sufficient to map the prospective zone around the well, but affords no regional insight. The data quality is adequate (see Figure 24). It has subsequently been ‘filtered’ by Eogas, a procedure which, while improving continuity, has almost certainly destroyed relative amplitude characteristics, and any subtleties in the data. The vertical resolution of the data, allied to the generally thin reservoir beds, means that reservoir thickness cannot be gauged from the seismic data. However, faults seem well-imaged on the filtered dataset, and for the purposes of structural interpretation the monochromatic seismic used by Eogas is perfectly good. Maps have been made on different horizons, and limited mapping by Hardy from the same dataset has confirmed that the contractor’s work is reliable.

The depth maps have almost certainly been made by applying a single Time- Depth curve from Atala-1 to the time maps. The depth maps have been used, with regional reservoir parameters and those derived from the well, to estimate hydrocarbon volumes. The results appear in a report for BOCL dated August, 2006, entitled “Geological & Engineering Data Re-evaluations and Production Design for Atala Field’s Development Programme”, by Eogas Petroleum & Geosciences Lagos, Nigeria. GCA considers that this represents a reliable assessment of the project.

The mapping shown in Figure 25 is Eogas’ time map at top U1.0 sand. It reveals much the same pattern as at Oza, with several parallel growth faults striking NW-SE. Within each fault terrace is some independent fault-bounded or four-way dip closure. The overall picture (see Figure 24) is of a broad rollover, intersected by numerous growth faults, dipping down toward a counter-regional fault zone and the main hydrocarbon generation area in the south west. Atala-1 was drilled on the southwest flank of a large anticlinal feature, with a collapsed crest located somewhere in the area of the Shell Dodo River-1 well which is 7 km north of Atala-1 and just 1 km beyond the northwest edge of the 3D seismic volume supplied by Shell. Dodo River-1 is about 305 m updip of Atala-1 at the U1.0 level, upthrown some three fault- blocks to the north, and the horizons which are hydrocarbon-bearing in Atala- 1, were found to be water-wet: however, there were, according to Eogas, indications of oil in the older E, F and G sand sequences immediately

Hardy 99 55 Gaffney, Cline & Associates

Atala Prospect NE SW DEPTH m TWT msec

Top U3

Top U6 Top U7

Atala-1

1 km

Atala Concession 3D Seismic Dip Line Through Atala-1 Well

Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 24 Hardy 56 100 Gaffney, Cline & Associates

Closure at U1.0 Sand

4 2 . g Fi

0312 km

C.I. = 10msec

LEGEND Surface Location

Location at U1.0 TD Location Atala Concession Seismic Time Map Near Top U1.0 Sand Source: Hardy Proj. E1741.01 Jan 08 Checked: Fig. 25 Hardy 57 101 Gaffney, Cline & Associates

beneath the “U” sequence. Dodo River-1 was regarded by Shell as uncommercial at the time of drilling in 1971, and plugged and abandoned.

The Atala-1 well is interpreted as restricted to a single fault-block, at least to the depth of the U7.0 horizon. Additional prospectivity is likely to exist in adjacent fault terraces. Analogue data and SPE recommended correlations were the only source to generate Atala’s indicative PVT parameters and pressure regimes for reservoir characterization and analysis.

Production from numerous other fields in the area indicates that the channel type reservoirs in the Atala region in the Niger Delta are reliable producers. However, significant production of basic sediments and water (BS&W) and probability of high GOR are also indicated in the area. Any plans to develop Atala should incorporate measures to minimise these effects.

Several estimates of in-place and Resource volumes were reviewed by GCA. Although gas potential is evident in Atala, the main focus has been on oil assessment.

There is broad agreement that the main gas reservoirs are the deepest (U6 to U7). However, Eogas is alone in attributing little or no oil to the U7 level. The rationale for this was that the drillpipe cemented in the original well-bore has affected the resistivity and formation density logging tools in the U6.5 and U7 zones, resulting in logs which could not be confidently interpreted.

GCA also reviewed a simplified simulation model developed by Hardy to investigate a possible development scenario for Atala to allow effective production of the oil leg in the presence of a large gas cap and bottom water. The model is a simple representation of Atala; however, GCA considered the results as reliable indications of the potential recovery factors expected to be achieved in an Atala development on the basis of the different scenarios assumed by Hardy.

Eogas (August, 2006) had 3D seismic, and adopted careful layer-by-layer evaluation of volumes and of reservoir parameters, and GCA is satisfied with the Eogas numbers for in place volumes. These are 395.0, 449.0 and 533 BCF for Low, Best and High estimates of GIIP and 27.6, 29.6 and 29.6 MMBbl for Low, Best and High estimates of STOIIP. GCA’s estimated gas and oil Contingent Resources for Atala are reported in Tables 5 and 6 respectively.

Hardy’s work programme proposed for Atala’s development considers, as a first step, the re-entry of Atala-1 well, to clean out the 7” liner and to test the casing integrity. If successful, Hardy intends to perform flow tests on three zones (U-7, U-4 & U-3) to estimate the potential.

Subsequently, Hardy intends to sidetrack Atala-1 horizontally and monitor the performance of the single horizontal well before drilling any further wells. Hardy also proposes an on–off production routine to mitigate gas coning and water cusping problems.

The preferred evacuation would be via a specially constructed flow-station and pipeline linking into an existing trunk route. For a preliminary period (up to a year), the use of a Floating Production Barge has been considered.

Hardy 102 58 Gaffney, Cline & Associates

GCA’s review of Hardy’s proposed work programme supports a Contingent Resources estimate for Atala.

Hardy 103 59 Gaffney, Cline & Associates

3. ECONOMIC EVALUATION

NPVs have been assigned to the ‘Proved’ and ‘Proved plus Probable’ Reserve categories, and have been calculated at nominal discount rates of 7.5%, 10% and 12.5%, these being discount rates considered by GCA to be typical of those Cost of Capital rates 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 the assets.

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 30th June, 2007) 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, do not represent a GCA postulation of the market value of that property, nor an interest in it. In assessing a likely market value, it would be necessary to take into account a number of additional factors including: reserve risk (i.e. that Proved and/or Probable and/or Possible reserves may not be realised); perceptions of economic and sovereign risk; potential upside, such as in this case exploitation of oil 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.

3.1 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 State 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.

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

Hardy 104 60 Gaffney, Cline & Associates

Alternative Tax rates are applicable. No tax positions were available for conducting the post-tax analysis on this basis.

Petroleum Income Tax: 42.23% Royalty: 0.0% Minimum Alternative Tax (MAT): 10.56%

3.2 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.

3.3 Oil Pricing

Hardy has advised that a quality discount of U.S.$0.35/Bbl to Brent is currently achieved for production from PY-3. GCA has used its Base Case scenario for prices and costs as its base case for NPV.

The Base Case Price Scenario is detailed below:

Base Case (U.S.$/Bbl) 2007 72.33 2008 73.48 2009 72.83 2010 68.04 2011 58.45 2012 59.62 Thereafter +2.0% p.a.

Other assumptions under this Price Scenario are:

1. The NPVs are net to Hardy’s Entitlement in its 18% working interest in PY-3; 2. The NPVs are effective from 30th June, 2007 3. All cash flows are discounted on a mid-year basis; 4. Costs are inflated at 2.0% per annum from 1st January, 2008 for Base Case Scenario; 5. No opening PSC or tax positions have been presumed.

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4. QUALIFICATIONS

GCA is an independent international energy advisory group of 45 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. William B. Cline, Dr S. Hattingh, Dr P.F. Worthington, Dr. B. Vining, Dr M.I. Hussain, Dr. R. French and Mr P. McGhee. All hold degrees in geoscience, petroleum engineering or related discipline. Mr. Cline is a Senior Partner and Principal of GCA, with over 48 years of industry experience. He has a BSc in Petroleum and Natural Gas Engineering, is a Chartered Engineer in the U.K. and Registered Professional Engineer in the State of Texas, U.S.A. He is also a Member of the Institute of Gas Engineers, the Society of Petroleum Engineers and the American Association of Petroleum Geologists. Dr. Hattingh is a senior petroleum engineer with 22 years industry and research experience. He has a Ph.D. in Applied Mathematics, MSc in Solar-Terrestrial Physics and B.Sc (Hons) in Geophysics. Dr. Worthington has a B.Sc (Hons) in Pure Maths and Physics, M.Sc in Geophysics, Ph.D. in Engineering Geophysics, D.Sc in Geology and D.Eng in Geoengineering, is a senior geoscientist with over 33 years international experience. Dr. Vining is a senior geoscientist with 31 years international exploration and production experience. He has a B.Sc and Ph.D. in Geology and is a fellow of the Geological Society. Dr. Hussain is a senior reservoir engineer with 25 years industry experience. She has a Ph.D. and M.Sc in Petroleum Engineering and is a member of the Society of Petroleum Engineers. Dr. French has 40 years experience and is a Fellow of the Geological Society, an Associate Member of the American Association of Petroleum Geologists and a member of the Petroleum Exploration Society of Great Britain. Mr. McGhee has over 23 years experience, he has a B.Sc in Chemical Engineering and is a member of the Society of Petroleum Engineers.

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5. 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.

William B. Cline, C.Eng. P.E.

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APPENDIX I

Glossary

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GLOSSARY

List of key abbreviations used in this report. oAPI Degrees API (American Petroleum Institute) B Billion (109) Bbl Barrels BCF Billion cubic feet BCM Billion cubic metres bcpd Barrels of condensate per day 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 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 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 NELP New Exploration Licensing Policy NPV Net Present Value NWI Net Working Interest/Net Participating Interest OCM Operating Committee Meeting OPEX Operating Expenditure

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GLOSSARY (Cont'd.) p.a. Per annum psi Pounds per square inch psig Pounds per square inch gauge PVT Pressure volume temperature 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 Te Tonnes equivalent TCM Technical Committee Meeting TOC Total Organic Carbon Tpd Tonnes per day TVDSS True Vertical Depth Subsea 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

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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.

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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.

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.

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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

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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.

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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.

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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.

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RESOURCES CLASSIFICATION

PROJECT MATURITY

Hardy 118 PART 4 — OPERATING AND FINANCIAL REVIEW

The following information should be read in conjunction with the financial information in this document, including the notes thereto and the basis of preparation thereof. Prospective investors should read the whole of this document and not rely on the summarised data. Certain of Hardy’s consolidated financial information has been prepared in accordance with IFRS, which differs from UK GAAP in certain respects. This discussion and analysis contains forward-looking statements that involve risks and uncertainties. Hardy’s actual results could differ materially from those expressed or implied by such forward-looking statements as a result of various factors, including those discussed below and elsewhere in this document. Factors that may cause such a difference include, but are not limited to, those discussed in ‘‘Forward-Looking Statements’’ and ‘‘Risk Factors’’. This operating and financial review includes information extracted from: • the financial information in respect of the nine months ended 30 September 2007 and 30 September 2006 prepared under IFRS as adopted by the European Union and presented in US dollars, as set out in part 5 of this document; • the financial information in respect of the years ended 31 December 2006 and 31 December 2005 prepared under IFRS as adopted by the European Union and presented in US dollars, as set out in part 5 of this document; and • the financial information in respect of the years ended 31 December 2005 and 31 December 2004 prepared under UK GAAP and presented in US dollars, as set out in part 5 of this document. Where different wording is used under IFRS and UK GAAP to describe equivalent items, the IFRS wording has been used. A full reconciliation of the results for the year ended 31 December 2006 and 31 December 2005 reported under UK GAAP to those reported under IFRS is set out in note 30 to the IFRS information in part 5 of this document. Principal activity and overview Hardy is an upstream international oil and gas company whose assets are held by its subsidiaries principally in India and to a lesser extent in Nigeria. Its portfolio includes a blend of production, development, appraisal and exploration assets. Hardy’s goal is to evaluate and exploit its asset base with a view to creating significant value for its Shareholders on a per share basis.

1.1 Income Statement

Operating Results Nine Months (Dollars in US thousands except otherwise Ended indicated and except per share amounts) 30 September Year Ended 31 December 2007 2006 2006 2005 2005 2004 IFRS IFRS IFRS IFRS UK GAAP UK GAAP Production (Barrels of Oil per Day) Gross Field 4,543 5,876 5,811 5,554 5,554 5,906 Participating Interest 821 1,058 1,046 1000 1000 1,063 Sales (Barrels of Oil per Day) Gross Field 3,547 4,099 5,831 6,141 6,141 5,284 Participating Interest 638 738 1,050 1,105 1,105 951 Net Entitlement Interest 463 562 850 899 899 895 Average Realized Price per Barrel – US $ 66.65 66.60 64.82 52.82 52.82 38.73 Revenue 11,719 15,390 21,317 17,574 17,574 13,719 Cost of Sales (4,449) (3,994) (5,192) (4,136) (4,868) (4,224) Gross Profit 7,270 11,396 16,125 13,439 12,706 9,495 Other Operating Income — 1,000 1,000 — — — Administrative Expenses (3,999) (4,708) (5,700) (4,916) (4,689) (2,419) Operating Profit 3,271 7,688 11,425 8,477 8,017 7,076

119 Production, sales and revenue The Company operates the PY-3 field in Cauvery Basin with an 18 per cent. participating interest. PY-3 field production averaged 5,811bopd in 2006 compared with 5,541 bopd in 2005. The increase is due to an improvement of production facility uptime to 99.8 per cent. compared to 91.6 per cent. in 2005. Production for 2005 was slightly down compared with 2004 due to a total of 22 days shutdown of the PY-3 production platform for maintenance. Since August 2007, one of the three producing wells in PY-3 field has been shut in due to excessive water entering in the well. Consequently, and as a result of natural decline, PY-3 field crude oil production averaged 4,560 bopd for the nine months ended 30 September 2007 compared with 5,857 bopd for the same period in 2006. Current oil production is at level of approximately 3,400 bopd. The Company does not expect to recover additional production until the implementation of PY-3 field’s phase III development. HEPI’s net entitlement interest in production is after the GOI’s share of Profit Oil. Under the terms of the PSC, the GOI’s share of Profit Oil increased from 10 per cent. to 25 per cent. effective 1 April 2005 and was further increased to 40 per cent. on 1 April 2006. On 1 April 2008, the Profit Oil is expected to increase to 50 per cent. Revenue has been steadily increasing from $13.7 million in 2004 to $17.6 million in 2005 to $21.3 million in 2006. The average price realised per barrel also steadily increased from $38.73 per barrel in 2004 to $52.82 per barrel in 2005 and to $64.82 per barrel in 2006. The increase in revenue resulted from higher oil prices offset in part by decline in sales in 2005 and the increase in Profit Oil entitlement for the GOI. The decline in revenue for the nine months ended 30 September 2007 results principally from lower sales volumes and a higher Profit Oil for the GOI.

Cost of sales The cost of sales includes production costs, depletion expense and a decommissioning charge. Cost of sales amounted to $12.14 per barrel in 2004 (under UK GAAP), $12.07 per barrel in 2005 (under UK GAAP), $10.25 per barrel (under IFRS) and $13.55 per barrel (under IFRS) in 2006. The increase in cost of sales between 2004 and 2005 under UK GAAP was mainly attributable to an increase in depletion resulting from the capitalisation of unsuccessful exploration wells in the India cost pool. Under IFRS, such costs are excluded from the full cost pool pending determination of commerciality. As a result, cost of sales declined in 2005 under IFRS compared to UK GAAP. Increase in per barrel cost in 2006 compared with 2005 reflects the impact of lower sales volumes and higher future development costs. Cost of sales for the nine months ended 30 September 2007 amounted to $25.54 per barrel compared $19.88 per barrel for the same period in 2006. Higher cost of sales reflect increased cost as a result of the contract extension of PY-3 operating facilities from July 2007 and a reduction in total volume of crude oil sales.

Gross profit As a result, gross profit has steadily increased from $9.5 million in 2004 to $12.7 million in 2005 (under UK GAAP). Gross profit increased to $13.4 million in 2005 (under IFRS) principally as a result of reduced depletion expense arising from the deferral of unsuccessful exploration costs pending determination of commerciality. Gross profit increased to $16.1 million in 2006 (under IFRS), principally as a result of higher revenues. Gross profit declined from $11.4 million for the nine months ended 30 September 2006 to $7.3 million, the reduction principally stemming from lower revenues.

Other operating income An insurance claim of $1.0 million was received for business interruption caused by an operational accident in the year 2002. This has been accounted for as other operating income in 2006 when insurance proceeds were received.

Administrative expenses Administrative expenses (under UK GAAP) increased from $2.4 million in 2004 to $4.7 million in 2005, reflecting the cost of running a publicly traded company listed on AIM. In 2005, an additional $0.3 million was expensed relating to pre-exploration expenditures associated with Nigeria under IFRS. Costs

120 increased from $4.9 million in 2005 to $5.7 million in 2006 partly as a result of additional legal costs associated with pursuing a claim under the shareholders’ agreement with HOEC, and the cost of share based payments in connection with the grant of stock options.

Operating profit

As a result, operating profits have steadily increased from 2004 to 2006. For the nine months ended 30 September 2007, operating profit has declined principally as a result of lower revenues.

Profit attributable to equity shareholders Nine Months (Dollars in US thousands except per share Ended amounts) 30 September Year Ended 31 December 2007 2006 2006 2005 2005 2004 IFRS IFRS IFRS IFRS UK GAAP UK GAAP Operating Profit 3,271 7,688 11,425 8,477 8,017 7,076 Investment and Other Income 917 1,578 2,289 890 890 231 Finance Costs (152) (240) (275) (361) (361) (275) Profit before Taxation 4,036 9,025 13,438 9,005 8,546 7,033 Taxation (1,240) (2,375) (3,205) (3,214) (3,101) (3,574) Net Profit 2,796 6,651 10,233 5,792 5,445 3,459 Earnings per Share Basic 0.05 0.12 0.18 0.12 0.11 0.10 Diluted 0.04 0.11 0.17 0.12 0.11 0.09

Investment and other income

Investment and other income has increased steadily from 2004 to 2006. The Company has successfully raised proceeds from equity financings in 2005, 2006 and 2007. Investment and other income reflects interest on short-term cash balances temporarily invested by the Company.

Investment and other income has declined from $1.6 million earned during the nine months ended 30 September 2006 to $0.9 million in the same period in 2007. The reduction in 2007 results from lower average cash balances during the period.

Finance costs

Finance costs principally include cost of providing bank guarantees to the GOI required in accordance with the provisions of PSCs and are based on agreed work programmes on blocks in India.

Taxation

Most of the provision for taxation is with respect to deferred income taxes, since the Company’s capital expenditure programme is sufficient to shield the Company from a large portion of current tax liabilities. Average tax rates reflect a blend of corporate income tax rates in India, United States and the United Kingdom to which the Company or its subsidiaries are subject.

Net profit

As a result, net profit has increased steadily over the three year period from $3.5 million in 2004 (under UK GAAP) to $10.2 million in 2006 (under IFRS). Net profit for the nine months ended 30 September 2007 declined to $2.8 million compared with a net profit of $6.7 million for the same period in 2006, principally as a result of lower revenues.

121 1.2 Cash Flows Nine Months Ended (Dollars in US thousands) 30 September Year Ended 31 December 2007 2006 2006 2005 2005 2004 IFRS IFRS IFRS IFRS UK GAAP UK GAAP Net Cash Generated from Operating Activities Before non cash working capital changes 5,707 10,080 14,555 9,700 9,973 8,615 Non cash working capital changes (7,964) 11,829 9,388 1,072 1,072 (1,891) Taxation paid (14) (132) (143) (972) (972) (2) (2,271) 21,777 23,800 9,799 10,072 6,722 Capital Expenditures (net of disposals) Oil and gas and other assets (29,189) (28,668) (51,607) (6,907) (7,179) (3,340) Investment in publicly traded company — (2,779) (2,779) — — — Site restoration deposits (553) (2,676) (2,785) Investment and Other Income 930 1,815 2,376 653 653 231 Finance Costs (152) (240) (275) (305) (305) (348) Proceeds from issue of Shares (net of costs) 40,169 24,527 24,527 20,772 20,772 1,788 Repayment of Bank and Other Loans — — — (1,861) (1,861) (1,441) Change in Cash and Cash Equivalent 8,933 13,756 (6,743) 22,152 22,152 3,612 Cash and Cash Equivalent – Beginning of Period 24,491 31,234 31,234 9,082 9,082 5,470 Cash and Cash Equivalent – End of Period 33,424 44,990 24,491 31,234 31,234 9,082

Cash flow from operating activities Cash flow from operating activities, before non-cash working capital, has steadily increased from $8.6 million in 2004, to $10.0 million in 2005 and to $14.6 million in 2006. The increase is in line with higher net profits during the period. Cash flow from operating activities, before changes in non-cash working capital for the nine months ended 30 September 2007 declined from $10.1 million in the same period in 2006 to $5.7 million, principally as a result of lower production volumes. Changes in non cash working capital principally reflect increases and decreases in trade and other payables associated with timing of work programmes, and the timing of crude oil sales from the PY-3 field. The tax payment in 2005 of $1.0 million principally relates to minimum alternate tax in India for which a refund is expected shortly.

Capital expenditures The Group’s capital expenditures have been increasing substantially over the past four years as its pace of exploration and development activities has been growing rapidly. Capital expenditures on oil and gas and other assets increased from $3.3 million in 2004 to $7.2 million in 2005 and rose significantly to $51.6 million in 2006. For the nine months ended 30 September 2007, capital expenditures were maintained at the level of the comparative previous period of approximately $29.2 million. During 2004, the bulk of capital expenditure was incurred on the PY-3 field. In 2005, HEPI acquired 654km2 of 3D seismic data over the CYOS/2 block and the PY-3 field in the Cauvery basin. In addition, in early 2005, 1,216km2 of 3D seismic data was acquired, processed and interpreted on the GS-01 licence block located off the west coast of India in the Gujarat-Saurashtra basin. Furthermore, 3D seismic data of 3,440km2 was acquired over the KG-DWN-2001/1 D9 block. Data interpretation and prospect mapping was ongoing. During 2006, HEPI incurred a significant amount of capital expenditures on the CY-OS/2 block. HEPI holds a 75 per cent. participating interest in the block. In the event that a discovery is declared commercial, ONGC has an option to assume a 30 per cent. interest in the block. During 2006, Hardy completed its committed work programme by drilling two exploration wells (Fan E-1 & Fan A-1) on the block. As of 31 December 2006, HEPI had invested $47.7 million for its share of the drilling and testing of the two wells

122 which included costs associated with the side track of the second well. In 2006, Hardy also participated in the drilling of the A-1 well on the GS-N-2000/1 block. The well is located 80km north-west of the extensive Bombay High oil field. In the Krishna Godavari Basin on the east coast of India, the Company has a 10 per cent. participating interest in two blocks, D9, and D3. Located in the Bay of Bengal, the Krishna Godavari Basin has been host to a number of oil and gas discoveries over the past three years. Reliance is the Operator for the blocks with Hardy holding a 10 per cent. participating interest. During 2006, 3,440km2 of 3D seismic data has been acquired over the D9 block, which has now been processed and interpreted, and six prospects have been identified for drilling. The D3 block has approximately 300km2 of 3D seismic data, which is being reprocessed. In addition, during 2007, Reliance acquired approximately 2,000km2 of 3D seismic data, covering a significant portion of the block. Several leads on the block have been identified from the current 3D data and on 31 December 2007, the Company announced the spudding of its first exploration well on the block. The Group’s capital expenditures amounted to $29.2 million during the nine months ended 30 September 2007, compared to $28.7 million incurred during the same period in 2006. Capital expenditures were primarily attributable to the drilling of the successful Fan A-1 (CY-OS/2 block) well, the drilling of the B-1 (GS-01 block) discovery well and seismic acquisition on the D3 exploration block. The management committee of the CY-OS/2 joint venture has agreed to a three-well programme to appraise the potential commerciality of the Fan A-1 discovery. In Nigeria, the Company holds working interests in two development blocks and is the technical partner with the local operators. Located within the Niger Delta, the Oza block is onshore and the Atala block is in a mangrove swamp. As of 30 September 2007, the Company has incurred $2.1 million of investment in Nigeria. Investment in HOEC As at 30 November 2007, Hardy held 6,657,694 shares or approximately 8.5 per cent. of the issued share capital of HOEC which is listed on both the National Stock Exchange of India and the Bombay Stock Exchange. As at 31 December 2007, HOEC had a market capitalisation of approximately US$324 million. In October 2006, HOEC raised approximately $33.0 million via a public rights issue in which Hardy took up its pro-rata entitlement, at a cost of $2.8 million. As of 30 September 2007, the market value of the Company’s investment in HOEC was $18.8 million. On 20 July 2007 HOEC announced that the HOEC Board of Directors had approved a rights issue for an amount not exceeding Indian Rupee 6,150 million. On 7 November 2007 HOEC announced that the HOEC board of directors had fixed the issue price at Rs. 117 per share and entitlement ratio of two equity shares for every three equity shares held. In early January 2008, HOEC completed the rights offering. Hardy participated in the rights offering, resulting in an acquisition of 4,438,462 additional shares in HOEC and a cash outlay of approximately $13.2 million. In December 2007 and January 2008, Hardy sold 4,981,411 shares in HOEC realising proceeds of approximately $20.6 million. On 14 February 2008, Hardy owned 6,114,745 shares of HOEC with a market value at such date of approximately $17.3 million, which represented approximately 4.7 per cent. of the entire issued share capital of HOEC. Site restoration deposits Up until 30 September 2007, the Company has deposited $3.3 million with an Indian bank with respect to deposits for site restoration of the PY-3 field. Of this amount, $2.7 million was placed in 2006 with the remainder in 2007. Investment and other income The Company has raised equity capital during the past three years. Surplus cash is invested in short term deposits generating investment income on a regular basis. As a result of the equity placing of $24.5 million in 2006, the level of investment income rose considerably during 2006. The level of such income was reduced from $1.8 million in the first nine months of 2006 to $0.9 million reflecting lower average cash balances as a result of an active capital programme. Finance costs Finance costs essentially represent the cost of bank guarantees provided to the GOI in connection with annual work programmes in India.

123 Equity financings The Company undertook its initial public offering (‘‘IPO’’) of Ordinary Shares on 7 June 2005 when its shares commenced trading on AIM. The IPO was successfully completed at a placing price of 144p per Ordinary Share, raising net proceeds of $20.8 million. In 2006 and 2007, the Company also successfully completed additional equity placings of Ordinary Shares at £2.76 and £4.23 respectively, raising additional proceeds of $24.5 million and $40.2 million respectively. Cash position As a result of the equity placings, the Company has been able to maintain significant amount of cash resources to fund its ongoing capital expenditures and work programmes. Total cash increased from $9.1 million at the end of 2004 to $31.2 million at the end of 2005. During 2006, capital expenditures exceeded proceeds realised from equity placements resulting in net cash resources being depleted to $24.5 million at the end of 2006. At 30 September 2007, the Company has cash resources in excess of $33.4 million to meet its ongoing requirements. 1.3 Summary balance sheets (Dollars in US thousands) 30 September 31 December 2007 2006 2005 2005 2004 IFRS IFRS IFRS UK GAAP UK GAAP Non Current Assets 122,399 89,119 38,665 23,161 17,117 Current Assets 38,605 31,858 35,928 36,673 13,242 Total Assets 161,004 120,977 74,593 59,834 30,359 Current Liabilities (6,659) (16,810) (5,268) (5,268) (5,585) Non Current Liabilities (15,388) (12,765) (8,395) (4,618) (1,296) Net Assets 138,957 91,402 60,930 49,948 23,478

Hardy has continued to grow over the past four years. Its non-current assets have increased from $17.1 million at the end of 2004 to $122.4 million at 30 September 2007. This results largely from its capital expenditure programme on exploration expenditures, principally on seismic expenditures on its blocks as well as on the drilling of wells on CY-OS/2 and GS-01. Current assets represent the Group’s cash resources, together with trade and other receivables and inventory. At 30 September 2007, of the $38.6 million of current assets, $33.4 million is represented by cash, generated principally from the equity issue that was completed in June 2007. Current liabilities are principally trade and other accounts payable. The level of current liabilities fluctuates significantly depending upon the timing of capital programmes. At the end of 2006, the Company was in the process of drilling a well on its CY-OS/2 operated block, resulting in a significant increase in payables. At 30 September 2007, the accounts payable were reduced to more normalised levels. Consequently, the Company has been successful in growing its net asset base, which has increased from $23.5 million at the end of 2004 to $139.0 million at 30 September 2007. The increase in the carrying value of net assets results from a combination of new equity placements and earnings that have been retained in the business which amounted to $33.3 million at 30 September 2007. Liquidity and capital resources Following the acquisition of the PY-3 field in 1999, Hardy had been funding its cash requirements from internally generated cash flows to grow its asset base until it became publicly traded in June 2005 upon the flotation of the Company on AIM. As part of the IPO and since the IPO, Hardy has raised equity capital in excess of $85 million, principally from institutional investors, in 2005, 2006 and 2007. The Company continues to be an emerging company with limited cash flows and, as a result, has been principally relying upon equity capital markets to build and grow its asset base. At 30 September 2007, the Company had cash resources of approximately $33 million that were available to meet future capital programs. Of this amount, approximately $10 million and $4 million were denominated in British pounds and Indian rupees respectively. In addition, as indicated above the Company has realised proceeds of $7.4 million (net of participation in the rights offering) from the sale of a portion of its shareholdings in HOEC which has augmented its cash resources and working capital. As at 14 February 2008 the Company’s remaining investment in HOEC was worth approximately $17.3 million, which can be made available to further augment the Company’s cash resources and working capital.

124 At the present time, the Company does not have any long term debt nor does it presently have any long term bank facilities in place. The Company’s wholly owned subsidiary, HEPI, has in place a $5 million non-revolving bank guarantee credit facility in connection with the issuance of bank guarantees to the Ministry of Petroleum & Natural Gas (GOI) for performance of PSCs (for exploration, development and production of oil and gas). HEPI has provided bank guarantees under this facility in an aggregate amount of $4,985,715 as at 11 January 2008. The Company presently produces from the PY-3 field in India and has announced a successful well test at Oza in Nigeria. The Company believes that it may be possible to secure financing on the strength of these assets in the future.

Key financial risks

Foreign exchange risk The proceeds of the Group’s domestic oil and gas sales in India are received in US dollars. The majority of the Group’s expenditure requirements are in US dollars. The Group has general and administrative expenditure with respect to offices in India, United Kingdom, and Nigeria, therefore the Group is exposed to foreign exchange risk against Indian Rupees, Nigerian Naira and UK Sterling. The Group has no current plans to enter into ongoing hedging arrangements. The Company has raised equity capital in the past and has received proceeds in UK Sterling. Such sterling funds have been converted into US and other currencies as required to fund cash requirements.

Liquidity risk The Group’s cash requirements and cash reserves are projected for the Group as a whole and for each country in which operations are conducted. Whereas the Group currently has no debt, going forward the Group expects to meet these requirements through an appropriate mix of available cash and assets, equity funds and debt financing. The Group further mitigates liquidity risk by maintaining an insurance programme to minimise exposure to insurable losses.

Commodity price risk Historically, oil prices have fluctuated widely and are affected by numerous factors over which the Group has no control, including world production levels, international economic trends, exchange rate fluctuations, expectations for inflation, speculative activity, consumption patterns and global or regional political events. The aggregate effect of these factors is impossible to predict. The production estimates for PY-3 and the oil prices will vary depending upon market conditions, which are not within the control of the Group. The Group’s production in India sold to CPCL is based on the 14 day average (seven day prior and seven day after crude delivery) of Brent Crude less $0.35. The Board has no immediate intention to enter into fixed price, long term marketing contracts. Pricing for production from future development assets in Nigeria has not been arranged. Although oil prices may fluctuate widely, it is the Group’s present policy not to hedge crude oil sales.

125 PART 5 — FINANCIAL INFORMATION

SECTION A FINANCIAL INFORMATION FOR THE NINE MONTHS ENDED 30 SEPTEMBER 2007 PREPARED IN ACCORDANCE WITH INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS) The following is the full text of a report on Hardy Oil and Gas plc from Horwath Clark Whitehill LLP, as reporting accountants: The Board of Directors Hardy Oil and Gas plc 15-19 Athol Street Douglas Isle of Man IM1 1LB The Directors Arden Partners plc Nicholas House 3 Laurence Pountney Hill London EC4R 0EU 15 February 2008 Dear Sirs Hardy Oil and Gas plc We report on the financial information set out Section A of part 5 of the prospectus dated 15 February 2008 of Hardy Oil and Gas plc (the ‘‘Company’’ and, together with its subsidiaries, the ‘‘Group’’) (the ‘‘Prospectus’’). This financial information has been prepared for inclusion in the Prospectus on the basis of the accounting policies set out in note 1. This report is required by Annex I item 20.1 of the Prospectus Directive and is given for the purpose of complying with that requirement and for no other purpose. Responsibilities The Directors of Hardy Oil and Gas plc are responsible for preparing the financial information on the basis of preparation set out in note 1 to the financial information and in accordance with International Financial Reporting Standards as adopted in the European Union. It is our responsibility to form an opinion as to whether the financial information gives a true and fair view, for the purposes of the Prospectus, and to report our opinion to you. Save for any responsibility arising under Prospectus Rule 5.5.3R(2)(f) to any person as and to the extent there provided, to the fullest extent permitted by law we do not assume any responsibility and will not accept any liability to any other person for any loss suffered by any such other person as a result of, arising out of, or in accordance with this report or our statement, required by and given solely for the purposes of complying with Annex I item 23.1 of the Prospectus Directive Regulation, consenting to its inclusion in the Prospectus. Basis of opinion We conducted our work in accordance with Standards for Investment Reporting issued by the Auditing Practices Board in the United Kingdom. Our work included an assessment of evidence relevant to the amounts and disclosures in the financial information. It also included an assessment of significant estimates and judgments made by those responsible for the preparation of the financial information and whether the accounting policies are appropriate to the entity’s circumstances, consistently applied and adequately disclosed. We planned and performed our work so as to obtain all the information and explanations which we considered necessary in order to provide us with sufficient evidence to give reasonable assurance that the financial information is free from material misstatement whether caused by fraud or other irregularity or error.

126 Opinion In our opinion, the financial information gives, for the purposes of the Prospectus, a true and fair view of the state of affairs of the Group as at 30 September 2007 and of its profits, cash flows and changes in equity for the nine month period ended 30 September 2007 in accordance with the basis of preparation set out in note 1 and in accordance with International Financial Reporting Standards as adopted in the European Union. We express no opinion on the profits, cash flows and changes in equity for the nine month period ended 30 September 2006 which is marked ‘‘unaudited’’.

Declaration For the purposes of Prospectus Rule 5.5.3R(2)(f) we are responsible for this report as part of the Prospectus and declare that we have taken all reasonable care to ensure that the information contained in this report is, to the best of our knowledge, in accordance with the facts and contains no omission likely to affect its import. This declaration is included in the Prospectus in compliance with item 1.2 of Annex I of the Prospectus Directive.

Yours faithfully

Horwath Clark Whitehill LLP

Chartered Accountants

127 HARDY OIL AND GAS plc Consolidated Income Statement For the period ended 30 September 2007

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 Notes US$ US$ Revenue 2 11,719,108 15,390,626 Cost of sales Production costs (3,253,889) (2,179,786) Depletion (1,028,796) (1,562,784) Decommissioning charge (166,141) (251,834) Gross profit 7,270,282 11,396,222 Other operating income 3 — 1,000,000 Administrative expenses (3,999,175) (4,708,671) Operating profit 3,271,107 7,687,551 Interest and investment income 9 917,056 1,577,710 Finance costs 10 (152,306) (239,887)

Profit on ordinary activities before taxation 4,035,857 9,025,374 Tax on profit on ordinary activities 11 (1,240,142) (2,374,762) Profit attributable to the equity shareholders of the parent company 2,795,715 6,650,612 Earnings per share Basic 12 0.047 0.118 Diluted 12 0.044 0.112

128 HARDY OIL AND GAS plc Consolidated Balance Sheet As at 30 September 2007

As at As at 30 September 31 December 2007 2006 Notes US$ US$ Assets Non-current assets Intangible assets – exploration 13 96,364,660 67,216,281 Intangible assets – others 14 132,194 217,198 Property, plant and equipment 15 3,787,764 5,064,070 Investment 16 18,777,039 13,836,910 Site restoration deposit 3,337,646 2,784,660 122,399,303 89,119,119 Current assets Inventory 18 1,727,856 2,729,764 Trade and other receivables 19 3,453,325 4,637,062 Cash and cash equivalents 20 33,424,168 24,490,939 38,605,349 31,857,765 Total assets 161,004,652 120,976,884 Liabilities Current liabilities Trade and other payables 21 (6,659,410) (16,809,807) (6,659,410) (16,809,807) Non-current liabilities Provisions for decommissioning 22 (4,500,000) (4,500,000) Provision for deferred tax 11 (10,888,619) (8,265,241) (15,388,619) (12,765,241) Total liabilities (22,048,029) (29,575,048) Net assets 138,956,623 91,401,836 Equity Called-up share capital 23 622,625 572,530 Share premium 24 93,101,579 52,982,983 Shares to be issued 24 1,973,581 940,093 Other reserves 24 9,921,602 6,364,709 Retained earnings 24 33,337,236 30,541,521 Total equity 138,956,623 91,401,836

129 HARDY OIL AND GAS plc Consolidated Statement of Cash Flows For the period ended 30 September 2007

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 Notes US$ US$ Operating activities Cash flow from operating activities 5 (2,257,052) 21,909,161 Taxation paid (13,928) (132,178) Net cash (used in) from operating activities (2,270,980) 21,776,983 Investing activities Expenditure on intangible assets − exploration (29,148,379) (28,200,436) Expenditure of property, plant and equipment (11,124) (143,282) Purchase of intangible fixed assets – others — (176,972) Purchase of other fixed assets (30,009) (147,883) Purchase of investment — (2,778,914) Site restoration deposit (552,986) (2,675,624) Net cash used in investing activities (29,742,498) (34,123,111) Financing activities Interest and investment income 930,322 1,814,804 Finance costs (152,306) (239,887) Issue of shares 40,168,691 24,527,092 Net cash from financing activities 40,946,707 26,102,009 Net increase in cash and cash equivalents 8,933,229 13,755,881 Cash and cash equivalents at the beginning of the period 24,490,939 31,234,376 Cash and cash equivalents at the end of period 19 33,424,168 44,990,257

130 HARDY OIL AND GAS plc Statement of Changes in Equity For the period ended 30 September 2007

1 January to Year ended 30 September 31 December 2007 2006 Notes US$ US$ Opening equity 91,401,836 60,929,902 Profit for the period 2,795,715 10,232,768 Valuation gain (loss) transferred to equity 4,940,129 (6,910,257) Differed tax (liability) asset on valuation gain or loss (1,383,236) 1,934,872 Total recognized gains and losses 6,352,608 5,257,383 New shares issued 40,168,691 24,527,092 Share based payments 24 1,033,488 687,459 Closing equity 138,956,623 91,401,836

131 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

1. ACCOUNTING POLICIES The following accounting policies have been applied in preparation of consolidated financial statements of Hardy Oil and Gas plc (‘‘Hardy’’ or the ‘‘Group’’). a) Basis of preparation Hardy prepares its financial statements on a historical cost basis except as otherwise stated. Investment in a publicly traded company is restated at fair market value. b) Accounting standards Hardy prepares its financial statements in accordance with applicable International Financial Reporting Standards (IFRS) and interpretations issued by the International Accounting Standards Board. c) Basis of consolidation The consolidated financial statements include the results of Hardy Oil and Gas plc and its subsidiary undertakings. The consolidated income statement and consolidated cash flow statements include the results and cash flows of subsidiary undertakings up to the date of disposal. The Group conducts the majority of its exploration, development and production through unincorporated joint arrangements with other companies. The consolidated financial statements reflect the group’s share of production and costs attributable to its participating interests under the proportional consolidation method. d) Revenue and other income Revenue represents the sale value of the Group’s share of oil which excludes the profit oil sold and paid to the Government as a part of profit sharing in the year, tariff, and the income from technical services to third parties if any. Revenues are recognized when crude oil has been lifted and title has been passed to the buyer or when services are rendered. e) Oil and gas assets

i) Exploration and evaluation assets Hardy follows the full cost method of accounting for its oil and gas assets. Under this method, all expenditures incurred in connection with and directly attributable to the acquisition, exploration and appraisal having regard to the requirements of IFRS 6 ‘‘Exploration for and Evaluation of Mineral Resources’’ are accumulated and capitalized in two geographical cost pools, which are not larger than a segment: India and Nigeria. The capitalized exploration and evaluation costs are classified as Intangible assets — exploration which includes the license acquisition, exploration and appraisal costs relating either to unevaluated properties or properties awaiting further evaluation but do not include costs incurred prior to having obtained legal right to explore an area, which are expensed directly to the income statement as they are incurred. Intangible exploration and evaluation cost relating to each license or block remain capitalized pending a determination of whether or not commercial reserves exists. Commercial reserves are defined as proven and probable on net entitlement basis. When a decision to develop these properties is taken or there is evidence of impairment, the costs are transferred to the cost pools within development/producing assets when the commercial reserves attributable to the underlying asset have been established.

ii) Oil and gas development and producing assets Development and production assets are accumulated on a field by field basis. These comprise of the cost of developing commercial reserves discovered putting them on production and the exploration

132 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

and evaluation costs transferred from intangible exploration and evaluation assets as stated in policy above. In addition, interest payable and exchange differences incurred on borrowings directly attributable to development projects if any and assets in the production phase as well as cost of recognizing provision for future restoration and decommissioning are capitalized.

iii) Decommissioning

At the end of the producing life of a field, costs are to be incurred in removing, decommissioning facilities, plugging and abandoning wells. Decommissioning costs are estimated and stated at an amount representing the costs, which would be incurred should decommissioning occur at the balance sheet date and the estimates are reassessed each year. The provision is assessed at prices ruling at the balance sheet date and, accordingly, it is not appropriate to discount this provision. The decommissioning asset is included within the tangible fixed assets with the cost of the related assets installed and are adjusted for any revision to the decommissioning costs and the provision thereof. The amortization of the asset, calculated on a unit of production basis based on proved and probable reserves, is shown as ‘‘Decommissioning charge’’ in the income statement.

iv) Disposal of assets

Proceeds from any disposal of assets are credited against the specific tangible or intangible capitalized costs included in the relevant cost pool and any loss or gain on disposal is recognized in the income statement. Gain or loss arising on disposal of a subsidiary is recorded in the income statement. f) Depletion and impairment

i) Depletion

The net book values of the producing assets are depreciated on a field by field basis using the unit of production method, based on proved and probable reserves taking into consideration future development expenditures necessary to bring the reserves into production. Hardy periodically obtains an independent third party assessment of reserves which is used as a basis for computing depletion.

ii) Impairment

Exploration assets are reviewed regularly for indications of impairment, if any, where circumstances indicate that the carrying value might not be recoverable. In such circumstances, if the exploration asset has a corresponding development/producing cost pool, then the exploration costs are transferred to the cost pool and depleted on unit of production. In cases where no such development/producing cost pool exists the impairment of exploration costs is recognized in the income statement. Impairment reviews on development/producing oil and gas assets for each field is carried out on each year by comparing the net book value of the cost pool with the associated discounted future cash flows. If there is any impairment in a field represents a material component of the cost pool, an impairment test is carried out for the cost pool as a whole. If the net book value of the cost pool is higher, then the difference is recognized in the income statement as impairment.

133 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007 g) Property, plant and equipment Property, plant and equipment other than oil and gas assets are measured at cost and depreciated over their expected useful economic lives as follows:

Annual Rate (%) Depreciation Method Leasehold improvements over lease period Straight line Furniture and fixtures 20% Straight line Information technology and computers 33% Straight line Other equipment 20% Straight line h) Intangible assets Intangible assets other than oil and gas assets are measured at cost and depreciated over their expected useful economic lives as follows:

Annual Rate (%) Depreciation Method Computer software 33% Straight line i) Investments Investments in publicly traded securities are recognized at fair values based upon the quoted market prices on the balance sheet date. Gain and losses are recognized under equity — other reserves. On disposal of an investment, the cumulative gain or loss is recognized in the income statement. j) Inventory Inventory of crude oil is valued at lower of the cost and market value. Cost being determined based on the production cost. Inventories of drilling stores and spares are accounted at cost including taxes duties and freight. Provision is made for obsolete, or defective items where appropriate based on technical evaluation. k) Financial instruments Financial assets and financial liabilities are recognized at fair value on the Group’s balance sheet based on the contractual provisions of the instrument. Trade receivables do not carry any interest and are stated at their nominal value as reduced by necessary provisions for estimated irrecoverable amounts. Trade payables are not interest bearing and are stated at their nominal value. l) Equity Equity instruments issued by Hardy and the Group are recorded at net proceeds after direct issue costs. m) Taxation The tax expense represents the sum of current tax and deferred tax. The current tax is based on the taxable profit of the year. Taxable profit differs from net profit as reported in the income statement as it excludes certain item of income or expenses that are taxable or deductible in years other than the current year and it further excludes items that are never taxable or deductible. The current tax liability is calculated using the tax rates that have been enacted or subsequently enacted by the balance sheet date. Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the liability method.

134 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

Deferred income tax liabilities are recognized for all taxable temporary differences and deferred tax assets are recognized to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilized.

Deferred income tax liabilities are recognized for all temporary differences except in respect of taxable temporary differences associated with investment in subsidiaries, associates and interest in joint ventures where the timing of the reversal of the temporary differences can be controlled and it is possible that the temporary differences will not reverse in the foreseeable future.

Deferred tax is recognized in respect of all temporary differences that have originated but not reversed at the balance sheet date where transactions or events have occurred at that date that will result in an obligation to pay more or a right to pay less or to receive more tax.

Deferred tax assets is reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow or part of the assets to be recovered.

Deferred tax assets and liabilities are measured on an undiscounted basis at the tax rates that are expected to apply in the periods in which temporary differences reverse, based on tax rates and laws enacted or substantively enacted at the balance sheet date. n) Foreign currencies

Hardy maintains its accounts and the accounts of its subsidiary undertakings in US dollars. Foreign currency transactions are accounted for at the exchange rate prevailing on the date of the transaction. At the year end, all foreign currency assets are restated at the average of the buying and the selling exchange rates prevailing at the balance sheet date. Exchange difference arising out of actual payments/realizations and from the year end restatement are reflected in the income statement.

Rate of exchanges were as follows:

30 September 31 December 2007 2006 £ to US$ 2.0204 1.9658 US$ to Indian Rupees 39.8000 44.1700 o) Leasing commitments

Rental charges or charter hire charges payable under operating leases are charged to the income statement as part of production expenses over the lease term. p) Share based payments

Hardy issues options to directors and employees, which are measured at fair value at the date of grant. The fair value of the equity settled options determined at the grant date is expensed on a straight line basis over the vesting period based on the actual number of shares vested in the accounting period. In performing the valuation of these options, only conditions other than the market conditions are taken into account. Fair value is derived by use of the binomial model. The expected life used in the model is based on estimates of the management considering non-transferability, exercise restrictions and behavioral considerations.

135 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

2. REVENUE AND OTHER INCOME

Unaudited 1 January to 1 January to 30 September 2007 30 September 2006 US$ US$ India UK India UK Oil sales 15,531,311 — 17,935,276 — Profit oil to government (4,268,322) — (3,511,667) — Other income — 456,119 — 967,017 11,262,989 456,119 14,423,609 967,017

The directors do not consider there to be more than one class of business or geographic segment as the revenue in other geographic segments are nil or less than 10 per cent. of the total revenue. Other income relates to technical services to third parties, overhead recovery from joint venture operations and miscellaneous receipts if any. Revenue arises from sale of oil produced from the contract area CY-OS- 90/1 — India and the revenue by destination is not materially different from the revenue by origin.

3. OTHER OPERATING INCOME

Other operating income relates to an insurance claim on business interruption received in 2006. The claim relates to an accident occurred in November 2002. This income has been accounted for based on the acceptance of the claim by the underwriters and receipt of payment.

4. OPERATING PROFIT

Operating profit is stated after charging:

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 US$ US$ Depletion charge of property, plant and equipment – producing 1,028,796 1,562,784 Decommissioning charge of property, plant and equipment – producing 166,141 251,834 Depreciation charge of property, plant and equipment – others 207,505 126,544 Movement in inventory of oil 7,166 (163,844) Operating lease costs – plant and machinery 2,196,304 1,357,982 – land and buildings 335,376 207,345 External auditors’ remuneration — 55,896 Exchange (gain) or loss (672,862) (45,568)

The Group has a policy in place for the award of non-auditor work to the auditors, which requires approval of the audit committee.

136 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

5. RECONCILIATION OF OPERATING PROFIT TO OPERATING CASH FLOWS

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 US$ US$ Operating profit 3,271,107 7,687,551 Depletion and depreciation 1,236,301 1,689,328 Decommissioning charge 166,141 251,834 Share based payments 1,033,488 451,661 5,707,037 10,080,374 Inventory movement 1,001,908 (2,956,681) Increase in debtors 1,184,399 1,489,434 Increase in creditors (10,150,396) 13,296,034 Net cash inflow from operating activities (2,257,052) 21,909,161

6. STAFF COSTS

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 US$ US$ Wages and salaries 2,340,064 1,743,078 Social security costs 99,094 121,580 Other pension costs 7,550 12,582 Share based payments 953,754 451,661 3,400,462 2,328,901

Staffs costs include executive directors’ salaries, fees, benefits, share based payments and are shown gross before amounts recharged to joint ventures.

The weighted average monthly number of employees, including executive Directors and individuals employed by the Group working on joint venture operations are as follows:

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 Management and administration 22 22 Operations 26 25 48 47

7. SHARE BASED PAYMENTS

Options had been granted to subscribe for ordinary shares which are exercisable between 2006 and 2016 at prices of £1.44 to £4.31. At 30 September 2007 there were 4,352,099 options outstanding.

Hardy has an unapproved share option scheme for the Directors and employees of the group. Options are exercisable at the quoted market price of the Company’s ordinary shares on the date of grant. The vesting period is three years with a stipulation that the options are granted in proportion to the period of employment after the grant subject to a minimum of one year. The options are exercisable for a period of ten years from the date of grant.

137 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

Details of the share options outstanding during the year are as follows:

30 September 2007 31 December 2006 Weighted Weighted Number of average price Number of average price options £ options £ Outstanding at beginning of the period 2,807,099 1.68 2,717,099 1.60 Granted during the period 1,835,000 3.78 135,000 3.09 Forfeited during the period (278,333) 2.79 (43,333) 1.60 Exercised during the period (45,002) 2.71 (1,667) 1.44 Outstanding at the end of the period 4,352,098 2.50 2,807,099 1.68 Exercisable at the end of the period 1,652,940 1.54 890,699 1.60

The aggregate of the estimated fair values of the options granted outstanding as on 30 September 2007 is US$7,229,634. The inputs into the binomial model for computation of value of options are as follows:

Share price at the grant date varies from £1.44 to £4.31 Option exercise price at grant date varies from £1.44 to £4.31 Expected volatility 8%-40% Expected life 6 years from grant date Risk free rate 4.35%-4.70% Expected dividend Nil

Expected volatility was determined by calculating Hardy’s historical volatility. The expected life used has been adjusted based on management’s best estimate for the effects of non-transferability, exercise restrictions and behavioral considerations.

The Group has recognized an expense of US$953,754 (2006: US$595,762) towards equity settled share based payments. Equity shares to be issued are revalued at the exchange rate as at 30 September 2007 and the value of shares to be issued as at 30 September 2007 is US$1,973,581 (31 December 2006: US$940,093).

8. DIRECTORS’ EMOLUMENTS

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 US$ US$ Directors emoluments 635,215 477,271 Highest paid 247,777 245,916

9. INTEREST AND INVESTMENT INCOME

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 US$ US$ Bank interest 917,056 1,537,534 Dividend — 40,176 917,056 1,577,710

138 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

10. FINANCE COSTS

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 US$ US$ Bank guarantee charges 151,905 239,887 Other finance charges 401 — 152,306 239,887

11. TAXATION ON PROFIT/(LOSS) a) Analysis of taxation charge for the period

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 US$ US$ Current tax charge UK Corporation Tax — — Foreign Tax India Minimum Alternate Tax on profits for the period — — Previous year provision reversed — (482,000) — (482,000) Foreign tax USA — 19,055 Alternate Minimum Tax on profits for the period — — Total current tax charge — (462,945) Deferred tax charges 1,240,142 2,837,707 Tax on profit on ordinary activities 1,240,142 2,374,762

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 US$ US$ Deferred tax charge: Origination and reversal of temporary differences 1,240,142 2,837,707 Deferred tax charges 1,240,142 837,707

139 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

Deferred tax analysis

Audited 30 September 31 December 2007 2006 US$ US$ Differences between accumulated depletion, depreciation and amortization and capital allowances (9,362,611) (18,706,663) Other temporary differences 1,260,000 1,451,218 Tax losses 1,072,393 11,465,369 Unrealized gain on investment (3,858,401) (2,475,165) Deferred tax (liability) (10,888,619) (8,265,241)

Factors affecting tax charge for the period

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 US$ US$ Profit on ordinary activities before tax 4,035,857 9,025,374 Profit on ordinary activities before tax multiplied by the rate of tax in UK of 30% 1,210,757 2,707,612 Mineral extraction and research allowances in excess of depreciation and utilisation of tax losses (1,210,757) (2,707,612) Effects of non taxable income — — Foreign tax on overseas income – current year – reversal of previous year provisions — (462,945) b) Indian operations of the Group are subject to a tax rate of 42.23 per cent. which is higher than UK and US corporations tax rates. As a double taxation avoidance agreement exists the group should be entitled to get the treaty benefit for the taxes paid in India. Based on the current expenditure plans, the group anticipates that the tax allowances will continue to exceed the depletion charge of each year though the timing of related tax relief is uncertain.

12. EARNINGS PER SHARE

Earnings per share are calculated on a profit of US$2,795,715 for the period 1 January to 30 September 2007 (1 January to 30 September 2006: US$6,650,612) on a weighted average of 59,400,679 ordinary shares as on 30 September 2007 (30 September 2006: 56,508,158).

The diluted earnings per share are calculated on a profit of US$2,795,715 for the period 1 January to September 2007 (1 January to 30 September 2006: US$ 6,650,612) on a weighted average of 63,752,778 ordinary shares as on 30 September 2007 (30 September 2006: 59,165,257). The weighted average shares are arrived after giving impact to dilutive potential ordinary shares of 4,352,099 as at 30 September 2007 (30 September 2006: 2,657,099) relating to share options.

140 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

13. INTANGIBLE EXPLORATION ASSETS

India Nigeria Total US$ US$ US$ Costs and net book value At 1 January 2006 15,359,126 823,151 16,182,277 Additions 50,430,702 603,302 51,034,004 At 1 January 2007 65,789,828 1,426,453 67,216,281 Additions 28,473,316 675,063 29,148,379 At 30 September 2007 94,263,144 2,101,516 96,364,660

14. INTANGIBLE ASSETS — OTHERS

US$ Cost At 1 January 2006 163,072 Additions 176,972 At 1 January 2007 340,044 Additions — At 30 September 2007 340,044 Accumulated depreciation At 1 January 2006 15,562 Charge for the period 107,284 At 1 January 2007 122,846 Charge for the period 85,004 At 30 September 2007 207,850 Net book value as at 30 September 2007 132,194 Net book value as at 31 December 2006 217,198

15. PROPERTY, PLANT AND EQUIPMENT

Oil and gas assets represent interest in producing oil and gas assets falling under the India cost pool. There are no oil and gas tangible assets currently in the Nigerian cost pool. Other tangible assets consist of office furniture, computers, workstations and office equipment.

141 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

Oil and gas Other fixed assets assets Total US$ US$ US$ Cost At 1 January 2006 23,217,681 2,287,644 25,505,325 Additions 2,784,494 247,992 3,032,486 Disposals — (1,683) (1,683) At 1 January 2007 26,002,175 2,533,953 28,536,128 Additions 11,124 30,009 41,133 At 30 September 2007 26,013,299 2,563,962 28,577,261 Depletion, depreciation and amortization At 1 January 2006 19,149,354 1,989,074 21,138,428 Charge for the period 2,192,810 142,503 2,335,313 Disposals — (1,683) (1,683) At 1 January 2007 21,342,164 2,129,894 23,472,058 Charge for the period 1,194,937 122,502 1,317,439 Disposals — — — At 30 September 2007 22,537,101 2,252,396 24,789,497 Net book value at 30 September 2007 3,476,198 311,566 3,787,764 Net book value at 31 December 2006 4,660,011 404,059 5,064,070

16. INVESTMENT

1 January to Year ended 30 September 31 December 2007 2006 US$ US$ Carrying value at beginning of period 13,836,910 17,968,252 Additional investment during the period — 2,778,914 Valuation gain (loss) during the period 4,940,129 (6,910,256) Carrying value at the end of period 18,777,039 13,836,910

Investment in a publicly traded company represents investment in 6,657,694 (31 December 2006 — 6,657,694) shares of Hindustan Oil Exploration Company Limited, which is listed in National Stock Exchange and Bombay Stock Exchange in India. The market value of the shares as at 30 September 2007 is Rs 112.25 per share based on the closing rate at National Stock Exchange on 30 September 2007 converted at an exchange rate of one US$ is equal to Rs 39.80. (31 December 2006: Price of Rs 91.80 per share at an exchange rate of 1 US$=Rs 44.17).

17. MEMBERS OF THE GROUP

The group comprises the parent company — Hardy Oil and Gas plc — and the following subsidiary companies, all of which are wholly owned:

• Hardy Exploration & Production (India) Incorporated under the laws of the State of Delaware, United States of America.

• Hardy Oil (Africa) Limited registered under the laws of the Isle of Man.

• Hardy Oil Nigeria Limited, owned by Hardy Oil (Africa) Limited registered under the laws of Nigeria.

All members of the Group are included in consolidation.

142 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

18. INVENTORY

At At 30 September 31 December 2007 2006 US$ US$ Crude oil 147,363 154,529 Drilling and production stores and spares 1,580,493 2,575,235 1,727,856 2,729,764

19. TRADE AND OTHER RECEIVABLES

At At 30 September 31 December 2007 2006 US$ US$ Trade receivables 1,179,928 2,363,197 Other receivables 911,353 931,640 Advance tax paid in India 1,108,531 985,659 Prepayments and accrued income 253,513 356,566 3,453,325 4,637,062

20. CONTINGENT LIABILITIES Bank guarantees for US$4,985,715 were issued to Government of India and the guarantees were obtained by placing a fixed deposit of Rs 22,787,223 (US$572,543) in the bank with the interest rate of 9.50 per cent. An amount of US$2,784,660 deposited with State Bank of India for site restoration obligation is treated as a non-current asset.

21. TRADE AND OTHER PAYABLES

At At 30 September 31 December 2007 2006 US$ US$ Trade payables 3,530,118 4,377,641 Other payables 926,662 1,853,415 Accruals 2,202,630 10,578,751 6,659,410 16,809,807

22. PROVISION FOR DECOMMISSIONING

1 January to Year ended 30 September 31 December 2007 2006 US$ US$ At beginning of period 4,500,000 1,863,720 Additional cost for decommissioning — 2,636,280 At end of period 4,500,000 4,500,000

The provision has been made by estimating the decommissioning cost at the current prices with the existing technology. Decommissioning costs are expected to be incurred between 2016 and 2020.

143 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

23. SHARE CAPITAL

Number $0.01 Ordinary Shares “000” US$ Authorised ordinary shares At 1 January 2007 200,000 2,000,000 At 30 September 2007 200,000 2,000,000

$0.01 Ordinary Shares US$ Allotted, issued and fully paid ordinary shares At 1 January 2006 52,046,667 520,467 Share options exercised 1,667 16 Shares issued 5,204,660 52,047 At 1 January 2007 57,252,994 572,530 Share options exercised 45,002 450 Shares issued 4,964,540 49,645 At 30 September 2007 62,262,536 622,625

24. RESERVES

Share Shares Other Retained premium to be issued reserves earnings US$ US$ US$ US$ At 1 January 2007 52,982,983 940,093 6,364,709 30,541,521 Share options exercised 245,527 — — — Issue of shares 41,593,363 — — — Issue expenses (1,720,294) — — — Shares to be issued — 1,033,488 — — Valuation gain (loss) — — 4,940,129 — Deferred tax on valuation gain (loss) — — (1,383,236) — Retained profit for the period — — — 2,795,715 At 30 September 2007 93,101,579 1,973,581 9,921,602 33,337,236

25. FINANCIAL INSTRUMENTS Hardy finances its operations through a mixture of retained earnings, additional equity and bank borrowings if required. Finance requirements such as equity, debt and project finance are reviewed by the board when substantial funds are required for acquisition, exploration and development of projects. Hardy’s principal financial instruments are cash and short term deposits and these instruments are only for the purpose of meeting its requirement for operations. All of the group’s sales are to a state oil company in India. Credit risk is minimal. Hardy’s main risks arising from financial instruments are foreign currency risk and liquidity risk. Hardy’s policy of managing the foreign currency risk and liquidity risk are as follows:

Foreign currency risk The group reports are in US dollars and the majority of its business is conducted in US dollars. All revenues from oil sales are received in US$ and all costs except a small portion towards expenses at

144 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

London office are incurred in US$. In case of currency exposure other than US$, a portion of the cash is kept in deposit in other currencies to meet its payments as required. No forward exchange contracts were entered into during the period.

Liquidity risk

The group deposits surplus cash on short term deposits ensuring sufficient liquidity to meet the group’s expenditure requirements. Hardy has no outstanding loan obligations at the end of the period.

Maturity of financial liabilities

The financial liabilities and its maturity as at 30 September 2007 and 31 December 2006 are as follows:

2007 2006 US$ US$ In more than two years but not more than five years — — In more than five years 4,500,000 4,500,000

The group does not have any fixed maturity and interest bearing financial liabilities as at 30 September 2007 or 31 December 2006.

Interest rate risk profile of financial assets

The interest rate risk of the financial assets of the group as at 30 September 2007 is as follows:

Fixed rate Floating rate Financial asset – Financial Financial no interest is asset asset earned Total US$ US$ US$ US$ US Dollars 18,894,389 801,850 2,907,004 22,603,243 Pound Sterling 9,759,014 211,689 24,896 9,995,599 Indian Rupees 3,910,189 — 243,984 4,154,173 Nigerian Niara — — 8,799 8,799 32,563,592 1,013,539 3,184,683 36,761,814

Financial assets include cash, deposits, short term investments if any and the floating interest rates are based on the base rate of the Bank of England.

The interest rate risk of the financial assets of the group as at 31 December 2006 is as follows:

Fixed rate Floating rate Financial asset – Financial Financial no interest is asset asset earned Total US$ US$ US$ US$ US Dollars 16,239,782 5,662,138 1,108,124 23,010,044 Pound Sterling — 243,566 44,472 288,038 Indian Rupees 3,178,646 — 784,649 3,963,295 Nigerian Niara — — 14,222 14,222 19,418,428 5,905,704 1,951,467 27,275,599

Financial assets include cash, deposits, short term investments if any and the floating interest rates are based on base rate of Bank of England.

145 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

Currency exposures

The currency exposures of the foreign currency monetary assets of the group as at 30 September 2007 are as follows:

Indian Pound Nigerian Rupees Sterling Naira Total US$ US$ US$ US$ US$ 4,154,173 9,995,599 8,799 14,158,571

An amount of US$653,056 was recognized as foreign exchange gain for the period 1 January to 30 September 2007.

The currency exchanges of the foreign monetary assets of the group as at 31 December 2006 are as follows:

Indian Pound Nigerian Rupees Sterling Naira Total US$ US$ US$ US$ US$ 3,963,295 288,038 14,222 4,265,555

An amount of US$99,952 was recognized as foreign exchange gain during the year ended 31 December 2006.

Fair values of financial assets and financial liabilities

Fair values of Hardy’s financial assets and liabilities excluding short term receivables and payables are compared as follows:

Book value Fair value Book value Fair value 30 September 30 September 31 December 31 December 2007 2007 2006 2006 Primary financial instruments US$ US$ US$ US$ Provisions for decommissioning (4,500,000) (4,500,000) (4,500,000) (4,500,000) Fixed asset investments 18,777,039 18,777,039 13,836,910 13,836,910 Cash and short term deposits 36,761,814 36,761,814 27,275,599 27,275,599 51,038,853 51,038,853 36,612,509 36,612,509

26. CAPITAL COMMITMENTS

At At 30 September 31 December 2007 2006 Oil and gas expenditure US$ US$

Intangible exploration/appraisal assets contracted for 207,304 21,164,000

27. PENSION COMMITMENTS

The Group has no pension commitments as at the balance sheet date.

146 HARDY OIL AND GAS plc Notes to Consolidated Financial Statements For the period ended 30 September 2007

28. OTHER FINANCIAL COMMITMENTS UNDER OPERATING LEASES Annual commitments under non-cancelable operating leases are as follows:

At At 30 September 31 December 2007 2006 US$ US$ Land and buildings, expiring within: One year 457,411 282,856 Two to five years 1,134,529 783,579 After five years — 89,333 Other operating leases, expiring within: One year 6,476,992 1,007,136 Two to five years 5,309,010 — After five years — —

Other operating lease commitments represent Hardy’s share of an operating lease for a floating production system entered into by the unincorporated joint venture.

29. CONTINGENT LIABILITIES The Group issues guarantees in respect of obligations under various Production Sharing Contracts (‘‘PSC’’) in the normal course of business. The Group has provided the guarantees for US$4,985,715 as at 30 September 2007 issued under the bank facility with Bank of Nova Scotia for the Group’s share of minimum work program commitments for the year 2007. The details of the bank guarantees provided are as follows:

PSC Guarantee Number US$ GS-OSN-2000/1 ILG009/42465/07 975,485 KG-DWN-2001/1 ILG010/42465/07 1,518,230 KG-DWN-2003/1 ILG011/42465/07 2,492,000 In addition parent company guarantees for the group’s obligation under the PSC’s were provided to Government of India.

30. RELATED PARTY TRANSACTIONS The remuneration of directors, who are the key management personnel of the group, are detailed below.

Unaudited 1 January to 1 January to 30 September 30 September 2007 2006 US$ US$ Short term employee benefits 567,715 409,771 Share based payments 594,720 220,719 1,162,435 630,490

147 SECTION B

FINANCIAL INFORMATION FOR THE YEARS ENDED 31 DECEMBER 2006 AND 2005 PREPARED IN ACCORDANCE WITH INTERNATIONAL FINANCIAL REPORTING STANDARDS (IFRS) The following is the full text of a report on Hardy Oil and Gas plc from Horwath Clark Whitehill LLP, as reporting accountants: The Board of Directors Hardy Oil and Gas Plc 15-19 Athol Street Douglas Isle of Man IM1 1LB The Directors Arden Partners plc Nicholas House 3 Laurence Pountney Hill London EC4R 0EU

15 February 2008 Dear Sirs

Hardy Oil and Gas plc We report on the financial information set out Section B of part 5 of the prospectus dated 15 February 2008 of Hardy Oil and Gas plc (the ‘‘Company’’ and, together with its subsidiaries, the ‘‘Group’’) (the ‘‘Prospectus’’). This financial information has been prepared for inclusion in the Prospectus on the basis of the accounting policies set out in note 1. This report is required by Annex I item 20.1 of the Prospectus Directive Regulation and is given for the purpose of complying with that requirement and for no other purpose.

Responsibilities The Directors of Hardy Oil and Gas plc are responsible for preparing the financial information on the basis of preparation set out in note 1 to the financial information and in accordance with International Financial Reporting Standards as adopted in the European Union. It is our responsibility to form an opinion as to whether the financial information gives a true and fair view, for the purposes of the Prospectus, and to report our opinion to you. Save for any responsibility arising under Prospectus Rule 5.5.3R(2)(f) to any person as and to the extent there provided, to the fullest extent permitted by law we do not assume any responsibility and will not accept any liability to any other person for any loss suffered by any such other person as a result of, arising out of, or in accordance with this report or our statement, required by and given solely for the purposes of complying with Annex I item 23.1 of the Prospectus Directive, consenting to its inclusion in the Prospectus.

Basis of opinion We conducted our work in accordance with Standards for Investment Reporting issued by the Auditing Practices Board in the United Kingdom. Our work included an assessment of evidence relevant to the amounts and disclosures in the financial information. It also included an assessment of significant estimates and judgments made by those responsible for the preparation of the financial information and whether the accounting policies are appropriate to the entity’s circumstances, consistently applied and adequately disclosed. We planned and performed our work so as to obtain all the information and explanations which we considered necessary in order to provide us with sufficient evidence to give reasonable assurance that the financial information is free from material misstatement whether caused by fraud or other irregularity or error.

148 Opinion In our opinion, the financial information gives, for the purposes of the Prospectus, a true and fair view of the state of affairs of the Group as at 31 December 2006 and 31 December 2005 and of its profits, cash flows and changes in equity for the years ended 31 December 2006 and 31 December 2005 in accordance with the basis of preparation set out in note 1 and in accordance with International Financial Reporting Standards as adopted in the European Union.

Yours faithfully

Horwath Clark Whitehill LLP

Chartered Accountants

149 HARDY OIL AND GAS plc Consolidated Income Statement For the year ended 31 December 2006

2006 2005 Notes US$ US$ Revenue 2 21,316,935 17,574,440 Cost of sales Production costs (2,999,086) (3,247,610) Depletion (1,887,911) (830,433) Decommissioning charge (304,899) (57,779) Gross profit 16,125,039 13,438,618 Other operating income 3 1,000,000 — Administrative expenses 4 (5,700,416) (4,961,660) Operating profit 5 11,424,623 8,476,958 Interest and investment income 10 2,288,954 890,096 Finance costs 11 (275,428) (361,204)

Profit on ordinary activities before taxation 13,438,149 9,005,850 Tax on profit on ordinary activities 12 (3,205,381) (3,213,644) Profit attributable to the equity shareholders of the parent company 10,232,768 5,792,206 Earnings per share Basic 13 0.18 0.12 Diluted 13 0.17 0.12

The notes on pages 154 to 178 form an integral part of these consolidated financial statements.

150 HARDY OIL AND GAS plc Consolidated Balance Sheet As at 31 December 2006

2006 2005 Notes US$ US$ Assets Non-current assets Intangible assets – exploration 14 67,216,281 16,182,277 Intangible assets – others 15 217,198 147,510 Property, plant and equipment 16 5,064,070 4,366,897 Investment 17 13,836,910 17,968,252 Site restoration deposit 2,784,660 — 89,119,119 38,664.936 Current assets Inventory 16 2,729,764 349,929 Trade and other receivables 17 4,637,062 4,343,755 Cash and cash equivalent 20 24,490,939 31,234,376 31,857,765 35,928,060 Total assets 120,976,884 74,592,996 Liabilities Current liabilities Trade and other payables 18 (16,809,807) (5,267,588) Non-current liabilities Provision for decommissioning 19 (4,500,000) (1,863,720) Provision for deferred tax 12 (8,265,241) (6,531,786) (12,765,241) (8,395,506) Total liabilities (29,575,048) (13,663,094) Net assets 91,401,836 60,929,902 Equity Called-up share capital 21 572,530 520,467 Share premium account 23 52,982,983 28,507,954 Shares to be issued 23 940,093 252,634 Other reserves 23 6,364,709 11,340,094 Retained earnings 23 30,541,521 20,308,753 Total equity 91,401,836 60,929,902

The notes on pages 154 to 178 form an integral part of these consolidated financial statements.

151 HARDY OIL AND GAS plc Consolidated Cash Flow Statement For the year ended 31 December 2006

2006 2005 Notes US$ US$ Operating activities Net cash flow from operating activities 6 23,942,864 10,771,715 Taxation paid (143,280) (972,329) Net cash from operating activities 23,799,584 9,799,386 Investing activities Purchase of intangible assets – exploration (51,034,004) (7,462,752) Purchase of property, plant and equipment (148,215) 1,177,176 Purchase of intangible fixed assets – others (176,972) (163,072) Purchase of other fixed assets (247,992) (458,012) Purchase of investment (2,778,914) — Site restoration deposit (2,784,660) — Net cash used in investing activities (57,170,757) (6.906,660) Financing activities Interest and investment income 2,376,072 653,002 Finance costs (275,428) (304,954) Issue of shares 24,527,092 20,772,691 Repayment of bank loan — (1,861,251) Net cash provided in financing activities 26,627,736 19,259,488 Net increase (decrease) in cash and cash equivalent (6,743,437) 22,152,214 Cash and cash equivalents at the beginning of the year 31,234,376 9,082,162 Cash and cash equivalents at the end of the year 24,490,939 31,234,376

The notes on pages 154 to 178 form an integral part of these consolidated financial statements.

152 HARDY OIL AND GAS plc Statement of Changes in Equity For the year ended 31 December 2006

2006 2005 US$ US$ Opening equity 60,929,902 28,146,604 Profit for the year 10,232,768 5,792,206 Valuation gain/(loss) transferred to equity – other reserves (6,910,256) 8,285,787 Deferred tax asset/(liability) on valuation gain or loss 1,934,871 (2,320,020) Total recognized gains and losses 5,257,383 11,757,973 Issue of shares 24,527,092 20,772,691 Share based payments 687,459 252,634 Closing equity 91,401,836 60,929,902

The notes on pages 154 to 178 form an integral part of these consolidated financial statements.

153 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

1. ACCOUNTING POLICIES The following accounting policies have been applied in preparation of consolidated financial statements of Hardy Oil and Gas plc (‘‘Hardy’’ or the ‘‘Group’’). a) Basis of preparation The consolidated financial statements have been prepared under the historical cost convention except as otherwise indicated. Investment in a publicly traded company is restated at fair market value. b) Accounting Standards Hardy prepares its consolidated financial statements in accordance with applicable International Financial Reporting Standards (‘‘IFRS’’) and interpretations issued by the International Accounting Standards Board. c) Basis of consolidation The consolidated financial statements include the results of Hardy Oil and Gas plc and its subsidiary undertakings. The consolidated income statement and consolidated cash flow statements include the results and cash flows of subsidiary undertakings up to the date of disposal. The Group conducts the majority of its exploration, development and production through unincorporated joint arrangements with other companies. The consolidated financial statements reflect the Group’s share of production revenues, costs and expenditures attributable to its participating interests under the proportional consolidation method. d) Revenue Revenue represents the sale value of the group’s share of oil which excludes the profit oil sold and paid to the government as part of profit sharing in the year, tariff, and income from technical services to third parties if any. Revenues are recognized when crude oil has been lifted and title has been passed to the buyer or when services are rendered. e) Oil and gas assets

i) Exploration and evaluation assets Hardy follows the full cost method of accounting for its oil and gas assets. Under this method, all expenditures incurred in connection with and directly attributable to the acquisition, exploration and appraisal having regard to the requirements of IFRS 6 ‘‘Exploration for and evaluation of mineral resources’’ are accumulated and capitalized in two geographical cost pools, which are not larger than a segment: India and Nigeria. The capitalized exploration and evaluation costs are classified as Intangible assets — exploration which includes the license acquisition, exploration and appraisal costs relating either to unevaluated properties or properties awaiting further evaluation but do not include costs incurred prior to having obtained legal right to explore an area, which are expensed directly to the income statement as they are incurred. Intangible exploration and evaluation costs relating to each license or block remain capitalized pending a determination of whether or not commercial reserves exists. Commercial reserves are defined as proven and probable reserves on a net entitlement basis. When a decision to develop these properties is taken or there is evidence of impairment, the costs are transferred to the cost pools within development/producing assets when the commercial reserves attributable to the underlying asset have been established.

154 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

ii) Oil and gas development and producing assets

Development and producing assets are accumulated on a field by field basis. These comprise of the cost of developing commercial reserves discovered putting them on production and the exploration and evaluation costs transferred from intangible exploration and evaluation assets as stated in policy above. In addition, interest payable and exchange differences incurred on borrowings directly attributable to development projects if any, and assets in the production phase as well as cost of recognizing provision for future restoration and decommissioning are capitalized.

iii) Decommissioning

At the end of the producing life of a field, costs are incurred in removing, decommissioning facilities, plugging and abandoning wells. Decommissioning costs are estimated and stated at an amount representing the costs, which would be incurred should decommissioning occur at the balance sheet date and the estimates are reassessed each year. The provision is assessed at prices ruling at the balance sheet date. The decommissioning asset is included within the tangible fixed assets with the cost of the related assets installed and are adjusted for any revision to the decommissioning costs and the provision thereof. The amortization of the asset, calculated on a unit of production basis based on proved and probable reserves, is reported as ‘‘Decommissioning charge’’ in the income statement.

iv) Disposal of assets

Proceeds from any disposal of any assets are credited against the specific tangible or intangible capitalized costs included in the relevant cost pool and any loss or gain on disposal is recognized in the income statement. Gain or loss arising on disposal of a subsidiary is recorded in the income statement. f) Depletion and impairment

i) Depletion

Net book value of the producing assets is depreciated on a field by field basis using the unit of production method, based on proved and probable reserves taking into consideration future development expenditures necessary to bring the reserves into production. Hardy periodically obtains an independent third party assessment of reserves which is used as a basis for computing depletion.

ii) Impairment

Exploration assets are reviewed regularly for indications of impairment, if any, where circumstances indicate that the carrying value might not be recoverable. In such circumstances, if the exploration asset has a corresponding development/producing cost pool, then the exploration costs are transferred to the cost pool and depleted on a unit of production. In cases where no such development/producing cost pool exists the impairment of exploration costs is recognized in the income statement. Impairment reviews on development/producing oil and gas assets for each field is carried out on each year by comparing the net book value of the cost pool with the associated discounted future cash flows. If there is any impairment in a field represents a material component of the cost pool, an impairment test is carried out for the cost pool as a whole. If the net book value of the cost pool is higher, then the difference is recognized in the income statement as impairment.

155 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006 g) Property, plant and equipment Property, plant and equipment other than oil and gas assets are measured at cost and depreciated over their expected useful economic lives as follows:

Annual Rate (%) Depreciation Method Computer software 33% Straight line i) Investments Investments in publicly traded securities are recognized at fair values based upon the quoted market prices on the balance sheet date. This investment is regarded as available for sale and as a result, unrealized gains and losses are recognized under equity — other reserves. On disposal of an investment the cumulative gain or loss is recognized in the income statement. j) Inventory Inventory of crude oil is valued at lower of the cost and market value, cost being determined based on production cost. Inventories of drilling stores and spares are accounted at cost including taxes duties and freight. Provision is made for obsolete or defective items based on technical evaluation of such assets. k) Financial Instruments Financial assets and financial liabilities are recognized at fair value on group’s balance sheet based on the contractual provisions of the instrument. Trade receivables do not carry any interest and are stated at their nominal value as reduced by necessary provisions for estimated irrecoverable amounts. Trade payables are not interest bearing and are stated at their nominal value. l) Equity Equity instruments issued by Hardy and the Group are recorded at net proceeds after direct issue costs. m) Taxation Tax expense represents the sum of current tax and deferred tax. Current tax is based on the taxable profit of the year. Taxable profit differs from net profit as reported in the income statement as it excludes certain item of income or expenses that are taxable or deductible in years other than the current year and it excludes items that are never taxable or deductible. The current tax liability is calculated using the tax rates that have been enacted by the balance sheet date. Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the liability method.

156 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Deferred tax assets are reviewed at each balance sheet date and reduced to the extent that it is no longer probable that sufficient taxable profits will be available to allow or part of the assets to be recovered.

Hardy maintains its accounts and the accounts of all subsidiary undertakings in US dollars. Foreign currency transactions are accounted for at the exchange rate prevailing on the date of the transaction. At year end, all foreign currency assets are restated at the average of the buying and the selling exchange rates prevailing at the balance sheet date. Exchange difference arising out of actual payments/realizations and from the year end restatements are reflected in the income statement.

Rates of exchange on the dates indicated were as follows: 31 December 31 December 2006 2005 £ to US$ 1.9658 1.7191 US$ to Indian Rupees 44.1700 45.1300 o) Leasing commitments

Rental charges or charter hire charges payable under operating leases are charged to the income statement as part of production expenses over the lease term. p) Share based payments

Hardy issues options to directors and employees, which are measured at fair value at the date of grant. The fair value of the equity settled options determined at the grant date is expensed on a straight line basis over the vesting period based on the actual number of shares vested in the accounting period. In performing the valuation of these options, only conditions other than the market conditions are taken into account. Fair value is measured by use of a binomial model. The expected life used in the model is based on estimates of the management considering non-transferability, exercise restrictions and behavioural considerations.

157 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

2. REVENUE AND OTHER INCOME

2006 2006 2005 2005 $ $ $ $ India UK India UK Oil sales 24,731,952 — 21,308,877 — Profit oil to government (4,714,128) — (3,983,854) — Other income 154 1,298,957 2,641 246,776 20,017,978 1,298,957 17,327,664 246,776

The directors do not consider there to be more than one class of business or geographic segment as the revenue in other geographic segments is less than 10 per cent. of the total revenue. Other income relates to technical services to third parties, overhead recovery from joint venture operations and miscellaneous receipts if any. Revenue arises from sale of oil produced from the contract area CY-OS-90/1 — India (PY-3) and the revenue by destination is not materially different from the revenue by origin.

3. OTHER OPERATING INCOME

4. ADMINISTRATIVE EXPENSES

Administrative expenses include an exceptional cost of $1,398,570 (2005: $925,038) relating to a dispute with respect to Hardy’s 8.5 per cent. equity shareholding in Hindustan Oil Exploration Company Limited.

5. OPERATING PROFIT

Operating profit is stated after charging: 2006 2005 $ $ Depreciation 249,788 82,393 Depletion 1,887,911 830,433 Decommissioning 304,899 57,779 Operating lease costs – Plant and machinery 1,803,478 1,887,686 – Land and buildings 292,881 162,450 External auditors’ remuneration – Fees payable to the Company’s auditors for the annual audit 64,871 34,081 – Other services 1,401 209,730 Exchange (gain)/loss (99,952) 578,990

The Group has a policy in place for the award of non-audit work to the auditors, which requires approval of the audit committee.

158 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

6. RECONCILIATION OF OPERATING PROFIT TO OPERATING CASH FLOWS 2006 2005 US$ US$ Operating profit 11,424,623 8,476,958 Depletion and depreciation 2,137,699 912,826 Decommissioning charge 304,899 57,779 Share based payments charges 687,459 252,634 14,554,680 9,700,197 (Increase)/decrease in inventory (2,379,835) 296,340 Decrease/(increase) in debtors 225,800 (986,329) Increase in creditors 11,542,219 1,761,507 Net cash inflow from operating activities 23,942,864 10,771,715

7. STAFF COSTS 2006 2005 US$ US$ Wages and salaries 2,363,687 1,956,093 Social security costs 144,493 93,662 Other pension costs 16,958 9,410 Share based payments 408,191 202,791 2,933,329 2,261,956

Staffs costs include executive directors’ salaries, fees, benefits and share based payments and are shown gross before amounts recharged to joint ventures.

The weighted average monthly number of employees, including executive directors and individuals employed by the Group working on joint venture operations are as follows: 2006 2005 Management and administration 22 18 Operations 26 26 48 44

8. SHARE BASED PAYMENTS

Share options have been granted to subscribe for Ordinary Shares which are exercisable between 2006 and 2015 at prices ranging from £1.44 to £3.38 per share. At 31 December 2006 there were 2,807,099 (31 December 2005 — 2,717,109) options were outstanding.

The Company has an unapproved share option scheme for the Directors and employees of the Group. Options are exercisable at the quoted market price of the Company’s ordinary shares on the date of grant. The options vest in three equal portions on the first, second and third anniversary of the grant, providing the option holder is employed by the Company. The Options are exercisable for a period of ten years from the date of grant, subject to vesting provisions.

159 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Details of the share options outstanding during the year are as follows: 2006 2005 Weighted Weighted average average Number of price Number of price options £ options £ Outstanding at the beginning of the year 2,717,099 1.60 — — Granted during the year 135,000 3.09 2,717,099 1.60 Forfeited during the year (43,333) 1.60 — — Exercised during the year (1,667) 1.44 — — Outstanding at the end of year 2,807,099 1.68 2,717,099 1.60 Exercisable at the end of the year 890,699 1.60 — —

The aggregate of the estimated fair values of the options granted outstanding as at 31 December 2006 is $1,824,215 (2005: $1,691,984). The inputs into the binomial model for computation of value of options are as follows: Share price at date of grant varies from £1.44 to £3.38 Option exercise price at date of grant varies from £1.44 to £3.38 Expected volatility 8.00% Expected life from grant date 6 years Risk-free rate 4.15% Expected dividend Nil

Expected volatility was determined by calculating the historical volatility of the Company’s weighted average share price over the period. The expected life used has been adjusted based on management’s best estimate for the effects of non-transferability, exercise restrictions and behavioural considerations.

The Group has recognised an expense of $595,762 (2005: $267,471) towards equity settled share based payments. Equity shares to be issued are revalued at the exchange rate as at 31 December 2006 and the value of shares to be issued as at 31 December 2006 is $940,093 (2005: $252,634).

9. DIRECTORS’ EMOLUMENTS 2006 2005 US$ US$ Directors’ emoluments 659,132 577,153 Highest paid 334,450 273,264

10. INTEREST AND INVESTMENT INCOME 2006 2005 US$ US$ Bank interest 2,137,665 724,526

11. FINANCE COSTS 2006 2005 US$ US$ Bank guarantee charges 267,985 361,204 Other finance charges 7,443 — 275,428 361,204

160 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

12. TAXATION a) Analysis of taxation charge 2006 2005 US$ US$ Current tax charge UK Corporation Tax — — Foreign tax – India Minimum Alternate Tax on profits for the year — 497,894 Previous year provision reversed (482,000) (179,000) (482,000) 318,894 Foreign tax – USA 19,055 — Minimum Alternate Tax on profits for the year — — Total current tax charge (462,945) 318,894 Deferred tax charges 3,668,326 2,894,750 Tax on profit on ordinary activities 3,205,381 3,213,644 Deferred tax charge: Origination and reversal of temporary difference 3,668,326 2,894,750 Deferred tax charge 3,668,326 2,894,750

Deferred tax analysis 2006 2005 US$ US$ Differences between accumulated depletion, depreciation and amortization and capital allowances (18,594,071) (4,362,359) Other temporary differences 1,338,626 591,842 Tax losses 11,465,369 1,648,767 Unrealized gain on investment (2,475,165) (4,410,036) Deferred tax (liability) (8,265,241) (6,531,786) b) Factors affecting tax charge 2006 2005 US$ US$ Profit on ordinary activities before taxation 13,438,149 9,005,850 Profit on ordinary activities before tax multiplied by the rate of tax in UK of 30% 4,021,282 2,701,755 Mineral extraction and research allowances in excess of depletion and utilisation of tax losses (4,021,282) (2,701,755) Effects of non taxable income — — Foreign tax on overseas income – Current year — 318,894 – Reversal of previous year provision (462,945) — c) Tax allowances The Indian operations of the Group are subject to a tax rate of 41.82% which is higher than UK and US corporate tax rates. Due to the existence of tax treaties the Group is entitled to receive credit for the taxes paid in India. Based on the current expenditure plans, the Group anticipates that the tax allowances will continue to exceed depletion charges of each year though the timing of related tax relief is uncertain.

161 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

13. EARNINGS PER SHARE

Earnings per share is calculated based on a profit of $10,232,768 (2005: $5,792,206) on a weighted average of 56,695,898 ordinary shares (2005: 47,871,777).

Diluted earnings per share is calculated on a profit of $10,232,768 (2005: $5,792,206) on a weighted average of 59,367,997 ordinary shares (2005: 50,588,876). The weighted average of shares is arrived at after giving impact to dilutive potential ordinary shares of 2,672,099 (2005: 2,717,099) relating to share options.

14. INTANGIBLE ASSETS — EXPLORATION India Nigeria Total US$ US$ US$ Costs and net book value At 1 January 2006 15,359,126 823,151 16,182,277 Additions 50,430,702 603,302 51,034,004 At 31 December 2006 65,789,828 1,426,453 67,216,281

India Nigeria Total US$ US$ US$ Costs and net book value At 1 January 2005 8,504,685 214,840 8,719,525 Additions 6,854,441 608,311 7,462,752 At 31 December 2005 15,359,126 823,151 16,182,277

15. INTANGIBLE ASSETS — OTHERS 2006 2005 US$ US$ Cost At beginning of year 163,072 — Additions 176,972 163,072 At end of year 340,044 163,072 Accumulated depreciation At beginning of year 15,562 — Charge for the year 107,284 15,562 At end of year 122,846 15,562 Net book value at end of year 217,198 147,510

16. PROPERTY, PLANT AND EQUIPMENT

Oil and gas assets represent interest in producing oil and gas assets falling under the Indian cost pool. There are no oil and gas tangible assets currently in the Nigerian cost pool. Other fixed assets consist of office furniture, computers, workstations and office equipment.

162 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Oil and gas development/producing assets Oil and gas Other fixed assets assets Total US$ US$ US$ Cost At 1 January 2006 23,070,171 2,450,703 25,520,874 Additions 2,714,807 424,964 3,139,771 Disposals — (1,683) (1,683) At 31 December 2006 25,784,978 2,873,984 28,658,962 Depletion, depreciation and amortisation At 1 January 2006 19,149,354 2,004,623 21,153,977 Charge for the year 2,192,810 249,788 2,442,958 Disposals — (1,683) (1,683) At 31 December 2006 21,342,164 2,252,728 23,594,892 Net book value at 31 December 2006 4,442,814 621,256 5,064,070

Oil and gas Other fixed assets assets Total US$ US$ US$ Cost At 1 January 2005 23,516,555 2,530,139 26,046,694 Additions (446,384) 464,000 17,616 Disposals — (543,436) (543,436) At 31 December 2005 23,070,171 2,450,703 25,520,874 Depletion, depreciation and amortisation At 1 January 2005 18,261,142 2,459,678 20,720,820 Charge for the year 888,212 82,393 970,605 Disposals — (537,448) (537,448) At 31 December 2005 19,149,354 2,004,623 21,153,977 Net book value at 31 December 2005 3,920,817 446,080 4,366,897

17. INVESTMENT 2006 2005 Shares in a publicly traded company US$ US$ Carrying value at beginning of year 17,968,252 9,682,465 Additional investment during year 2,778,914 — Valuation gain (loss) during the year (6,910,256) 8,285,787 Carrying value at end of year 13,836,910 17,968,252

The investment in a publicly traded company represents an investment in 6,657,694 (2005: 4,993,271) equity shares of an Indian company, Hindustan Oil Exploration Company Limited, listed on the National Stock Exchange and the Bombay Stock Exchange in India. The market value of the shares as at 31 December 2006 was $13.84 million based on Rs91.80 per share quoted at National Stock Exchange on 30 December 2006 converted at an exchange rate of one US$ = Rs44.17 (2005: $17.97 million at a price of Rs167 per share at an exchange rate of 1US$ = Rs45.13). 18. MEMBERS OF THE GROUP The group comprises the parent company — Hardy Oil and Gas plc — and the following subsidiaries all of which are wholly owned: • Hardy Exploration & Production (India) Inc incorporated under the laws of the State of Delaware, United States of America.

163 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

• Hardy Oil (Africa) Limited registered under the laws of the Isle of Man.

• Hardy Oil Nigeria Limited wholly owned by Hardy Oil (Africa) Limited registered under the laws of Nigeria.

All members of the Group are included in the consolidation.

19. INVENTORIES 2006 2005 US$ US$ Crude oil 154,529 180,415 Drilling and production stores and spares 2,575,235 169,514 2,729,764 349,929

20. TRADE AND OTHER RECEIVABLES 2006 2005 US$ US$ Trade debtors 2,363,197 2,308,459 Other debtors 931,640 486,548 Advance tax paid in India 985,659 379,435 Prepayments and accrued income 356,566 1,169,313 4,637,062 4,343,755

21. TRADE AND OTHER PAYABLES 2006 2005 US$ US$ Trade creditors 4,377,641 2,279,086 Other creditors 1,853,415 1,036,705 Accruals 10,578,751 1,951,797 16,809,807 5,267,588

22. PROVISION FOR DECOMMISSIONING 2006 2005 US$ US$ At beginning of year 1,863,720 1,296,000 Additional cost for decommissioning 2,636,280 567,720 At end of year 4,500,000 1,863,720

The provision has been made by estimating the decommissioning cost at the current prices prevailing at balance sheet date with the existing technology. All decommissioning costs are expected to be incurred between 2016 and 2020.

164 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

23. SHARE CAPITAL Number $0.01 ordinary shares ’000 US$ Authorised ordinary shares At beginning of year 200,000 2,000,000 At end of year 200,000 2,000,000

2006 2005 $0.01 ordinary $0.01 ordinary shares US$ shares US$ Allotted, issued and fully paid ordinary shares At beginning of year 52,046,667 520,467 411,096 4,111 Converted to redeemable preference shares (48,796) (488) Bonus shares issued 41,213,700 412,137 Share options exercised 1,667 16 54,000 540 Shares issued 5,204,660 52,047 10,416,667 104,167 At end of year 57,252,994 572,530 52,046,667 520,467

24. RESERVES Share Shares Other Retained premium to be issued reserves earnings US$ US$ US$ US$ At 1 January 2006 28,507,954 252,634 11,340,093 20,308,753 Share options exercised 4,418 — — — Issue of shares 25,542,863 — — — Valuation gain/(loss) — — (6,910,256) — Deferred tax on valuation gain (loss) — — 1,934,872 — Issue expenses (1,072,252) — — — Shares to be issued — 687,459 — — Retained earnings for the year — — — 10,232,768 At 31 December 2006 52,982,983 940,093 (6,364,709) 30,541,521

Share Shares Other Retained premium to be issued reserves earnings US$ US$ US$ US$ At 1 January 2005 8,251,619 — 5,374,327 14,516,547 Redemption of preference shares (5,855,032) — — — Valuation gain/(loss) on investment — — 8,285,787 — Deferred tax on valuation gain/(loss) — — (2,320,020) — Bonus shares (412,137) — — — Share options exercised 1,251,860 — — — Issue of shares 27,255,834 — — — Issue expenses (1,984,190) — — — Shares to be issued — 252,634 — — Retained earnings for the year — — — 5,792,206 At 31 December 2005 28,507,954 252,634 11,340,094 20,308,753

165 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

25. FINANCIAL INSTRUMENTS Hardy finances its operations through equity and bank borrowings if required. Finance requirements such as equity, debt and project finance are reviewed by the Board when substantial funds are required for acquisition, exploration and development of projects. Hardy’s principal financial instruments are cash and short-term deposits and these instruments are only for the purpose of meeting its requirements for operations. All of the group’s sales are to a state oil company in India. Credit risk is minimal. Hardy’s main risks arising from financial instruments are foreign currency risk and liquidity risk. Hardy’s policy of managing the foreign currency risk and liquidity risk are as follows:

Foreign currency risk The Group reports are in US dollars and the majority of its business is conducted in US dollars. All revenues from oil sales are received in US dollars and all costs except a small portion towards expenses at London office are incurred in US dollars. In case of currency exposure other than dollars, a portion of the cash is kept on deposit in the other currencies to meet payments as required. No forward exchange contracts were entered into during the year.

Liquidity risk The Group deposits the surplus cash on short term deposits ensuring sufficient liquidity to meet the Group’s expenditure requirements. The Company has no outstanding loan obligations at the end of the year. a) Maturity of financial liabilities The financial liabilities and its maturity as at 31 December are as follows: 2006 2005 US$ US$ In more than two years but not more than five year — — In more than five years 4,500,000 1,863,720

The Group does not have any fixed maturity and interest bearing financial liabilities as at 31 December 2006 or 31 December 2005. b) Interest rate risk profile of financial assets The interest rate risk of the financial assets of the Group as at 31 December 2006 is as follows: Financial Fixed rate Floating rate asset – financial financial no interest asset asset is earned Total US$ US$ US$ US$ US Dollars 16,239,782 5,662,138 1,108,124 23,010,044 Pound Sterling — 243,566 44,472 288,038 Indian Rupees 3,178,646 — 784,649 3,963,295 Nigerian Naira — — 14,222 14,222 19,418,428 5,905,704 1,951,467 27,275,599

Disclosed as: Site restoration deposit 2,784,660 Cash and cash equivalent 24,490,939 27,275,599

166 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Financial assets include cash, deposits and short-term investments if any and the floating interest rates are based on the Bank of England base rate. The interest rate risk of the financial assets of the Group as at 31 December 2005 was as follows: Financial Fixed rate Floating rate asset – financial financial no interest asset asset is earned Total US$ US$ US$ US$ US Dollars 14,413,128 7,216,626 1,603,707 23,233,461 Pound Sterling 3,529,203 361,883 31,081 3,922,167 Indian Rupees 3,959,270 — 116,112 4,075,382 Nigerian Naira — — 3,366 3,366 Cash and cash equivalent 21,901,601 7,578,509 1,754,266 31,234,376

Financial assets include cash, deposits and short-term investments if any and the floating interest rates are based on the Bank of England base rate. Currency exposures The currency exposures of the foreign currency monetary assets of the Group as at 31 December 2006 is as follows: Indian Pound Nigerian Rupees Sterling Naira Total US$ US$ US$ US$ US dollars 3,963,295 288,038 14,222 4,265,555

The currency exposures of the foreign currency assets of the Group as at 31 December 2005 is as follows: Indian Pound Nigerian Rupees Sterling Naira Total US$ US$ US$ US$ US dollars 4,075,382 3,922,167 3,366 8,000,915 c) Fair values of financial assets and financial liabilities Fair values of Hardy’s financial assets and liabilities excluding short term trade and other receivable and trade and other payables are as follows: Book value Fair value Book value Fair value 31 December 31 December 31 December 31 December 2006 2006 2005 2005 US$ US$ US$ US$ Provisions for decommissioning (4,500,000) (4,500,000) (1,863,720) (1,863,720) Investments 13,836,910 13,836,910 17,968,252 17,968,252 Cash and short-term deposits 27,275,599 27,275,599 31,234,376 31,234,376 36,612,509 36,612,509 47,338,908 47,338,908

26. CAPITAL COMMITMENTS 2006 2005 US$ US$ Oil and gas intangible exploration expenditures 21,164,000 —

167 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

27. OTHER FINANCIAL COMMITMENTS UNDER OPERATING LEASES Annual commitments under non-cancellable operating leases are as follows: 2006 2005 US$ US$ Land and buildings, expiring within: – One year 282,856 203,477 – Two to five years 783,579 141,341 – After five years 89,333 — Other operating leases, expiring within: – One year 1,007,136 1,767,330 – Two to five years — 1,007,136 – After five years — —

Other operating lease commitments represent Hardy’s share of an operating lease for a floating production platform and storage systems entered into by the unincorporated joint venture. The Group does not have any pension commitments at balance sheet dates. 28. CONTINGENT LIABILITIES At 31 December 2005, bank guarantees were issued to the Government of India for the block GS-OSN- 2000/1. The guarantee was obtained by placing a fixed deposit of Rs.17,402,343 ($393,986) in the bank with an interest rate of 6.75 per cent. 29. RELATED PARTY TRANSACTIONS The remuneration of Directors, who are the key management personnel of the group, are detailed below. 2006 2005 US$ US$ Short term employee benefit 569,132 512,153 Share based payments 294,292 171,670 863,424 683,823

30. TRANSITION TO IFRS Hardy Oil and Gas Plc (‘‘Hardy’’ or the ‘‘Group’’) has a mandatory requirement to implement International Financial Reporting Standards (herein after referred to as ‘‘IFRS’’) for accounting periods commencing from 1 January 2007. In order to comply with IFRS, Hardy has restated its consolidated financial statements for 2005 and 2006 and has revised its accounting policies. Hardy has also prepared reconciliation of its consolidated financial statements under UK GAAP to those prepared under IFRS. The principal differences between reporting under UK GAAP and IFRS for Hardy are as follows: 1. Pre-exploration expenditures which were capitalized under UK GAAP are expensed under IFRS. 2. Under UK GAAP, unsuccessful exploration costs were transferred from intangible fixed assets to tangible fixed assets and depletion based upon the unit of production method. Under IFRS, unsuccessful exploration costs are capitalized under intangible assets — exploration pending a determination of whether or not commercial reserves exist. 3. Depletion expense under IFRS has been reduced as a result of 2 above compared to UK GAAP. Depletion expense under IFRS is determined on a field by field basis as compared to on a cost pool basis under UK GAAP. 4. Investments are stated at fair value and gains are reflected in equity — other reserves.

168 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

5. Deferred tax adjustments have been made as a result of reduction of depletion in the income statement. Deferred tax is also provided on unrealized gains on investments and charged to equity — other reserves. Hardy has continued to follow its existing full cost accounting policy for oil and gas assets to both exploration and appraisal activity and the assets in the development and production phases except those above. SUMMARY IMPACT OF IFRS ON GROUP RESULTS The principal changes to the Group’s reported consolidated 2006 financial information from the adoption of IFRS are as follows: 2006 2005 Effects of Effects of UK GAAP transition IFRS UK GAAP transition IFRS US$ million US$ million US$ million US$ million US$ million US$ million Income statement Revenue 21.32 — 21.32 17.57 — 17.57 Gross profit 12.94 3.18 16.12 12.71 0.73 13.44 Operating profit 8.24 3.18 11.42 8.02 0.46 8.48 Profit before taxation 10.25 3.18 13.43 8.55 0.46 9.01 Profit for the year 7.99 2.24 10.23 5.44 0.35 5.79 US cents US cents US cents US cents US cents US cents Earnings per share Basic 14 4 18 0.11 0.01 0.12 Diluted 13 4 17 0.11 0.01 0.12 US$ million US$ million US$ million US$ million US$ million US$ million Balance Sheet Net assets 83.16 8.24 91.40 49.95 10.98 60.93

The changes are as a result of the following: i) Incorporation of changes in presentation of financial information in the form of IFRS in line with International Accounting Standards-1. ii) Pre-exploration expenditures which were capitalized under UK GAAP are expensed under IFRS. iii) Tangible fixed assets have been renamed as ‘‘property, plant and equipment’’ and the expenses of dry holes which were capitalized as tangible assets under the India cost pool have been reclassified as Intangible assets — exploration in line with IFRS-6. iv) Software costs were capitalized and included in the tangibles assets under UK GAAP and are now transferred to Intangible assets — others under IFRS. v) In the Cash Flow Statement under IFRS, cash flows have been grouped under three main headings as cash flows from operating, investing and financing activities. The deposit made with State Bank of India to meet the site restoration obligations is removed from cash and cash equivalent and included in ‘‘site restoration deposit’’. Consequent to the above, certain changes in the presentation were made under IFRS though there is no material movement in cash and cash equivalents. vi) Development and production assets within property, plant and equipment have been depleted according to the unit of production method on an individual field basis in line with IAS-16, whereas under UK GAAP they were grouped into regional cost pools and depleted accordingly. vii) Investment in equity is stated at fair value based on the market price and the consequent adjustments were made in equity — other reserves. viii) Deferred tax adjustments have been made as a result of reduction of depletion in the income statement. Deferred tax is also provided on unrealized gains on investments and charged to equity — other reserves.

169 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Consolidated Income Statement

For the year ended 31 December 2006 Effect of transition UK GAAP to IFRS IFRS US$ US$ US$ Revenue 21,316,935 — 21,316,935 Cost of sales Production costs (2,999,086) — (2,999,086) Depletion (5,072,414) 3,184,503 (1,887,911) Decommissioning charge (304,899) — (304,899) Gross profit 12,940,536 3,184,503 16,125,039 Other operating income 1,000,000 — 1,000,000 Administrative expenses (5,700,416) — (5,700,416) Operating profit 8,240,120 3,184,503 11,424,623 Interest and investment income 2,288,954 — 2,288,954 Finance costs (275,428) — (275,428)

Profit on ordinary activities before taxation 10,253,646 3,184,503 13,438,149 Tax on profit on ordinary activities (2,260,193) (945,188) (3,205,381) Profit attributable to the equity shareholders of the parent company 7,993,453 2,239,315 10,232,768 Earnings per share Basic 0.14 0.04 0.18 Diluted 0.13 0.04 0.17

170 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Consolidated Balance Sheet

At 31 December 2006 Effect of transition UK GAAP to IFRS IFRS US$ US$ US$ Assets Non-current assets Intangible assets – exploration 33,788,334 33,427,947 67,216,281 Property, plant and equipment 35,770,629 (30,706,559) 5,064,070 Intangible assets – others — 217,198 217,198 Investment 4,997,036 8,839,874 13,836,910 Site restoration deposit — 2,784,660 2,784,660 74,555,999 14,563,120 89,119,119 Current assets Inventories 2,729,764 — 2,729,764 Trade and other receivables 4,637,062 — 4,637,062 Cash and cash equivalents 27,275,599 (2,784,660) 24,490,939 34,642,425 (2,784,660) 31,857,765 Total assets 109,198,424 11,778,460 120,976,884 Liabilities Current liabilities Trade and other payables (16,809,807) — (16,809,807) (16,809,807) — (16,809,807) Non-current liabilities Provisions for liabilities and charges (4,500,000) — (4,500,000) Provision for deferred tax (4,732,296) (3.532,945) (8,265,241) (9,232,296) (3,532,945) (12,765,241) Total liabilities (26,042,103) (3,532,945) (29,575,048) Net assets 83,156,321 8,245,515 91,401,836 Equity Called-up share capital 572,530 — 572,530 Share premium account 52,982,983 — 52,982,983 Shares to be issued 940,093 — 940,093 Other reserves — 6,364,709 6,364,709 Retained earnings 28,660,715 1,880,806 30,541,521 Total equity 83,156,321 8,245,515 91,401,836

171 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Consolidated Cash Flow Statement

For the year ended 31 December 2006 Effect of transition UK GAAP to IFRS IFRS US$ US$ US$ Operating activities Cash flow generated by operations 23,942,864 — 23,942,864 Taxation paid (143,280) — (143,280) Net cash from operating activities 23,799,584 — 23,799,584 Investing activities Purchase of intangible assets – exploration (51,034,004) — (51,034,004) Purchase of property, plant and equipment (148,215) — (148,215) Purchase of intangible fixed assets – others — (176,972) (176,972) Purchase of other fixed assets (424,964) 176,972 (247,992) Purchase of investment (2,778,914) — (2,778,914) Site restoration deposit — (2,784,660) (2,784,660) Net cash used in investing activities (54,386,097) (2,784,660) (57,170,757) Financing activities Interest and investment income 2,376,072 — 2,376,072 Finance costs (275,428) — (275,428) Issue of shares 24,527,092 — 24,527,092 Net cash provided in financing activities 26,627,736 — 26,627,736 Net decrease in cash and cash equivalents (3,958,777) (2,784,660) (6,743,437) Cash and cash equivalents at the beginning of the year 31,234,376 — 31,234,376 Cash and cash equivalents at the end of the year 27,275,599 (2,784,660) 24,490,939

Consolidated Statement of Changes in Equity

For the year ended 31 December 2006 Effect of transition UK GAAP to IFRS IFRS US$ US$ US$ Opening equity 49,948,317 10,981,585 60,929,902 Profit for the year 7,993,453 2,239,315 10,232,768 Valuation gain/(loss) transferred to equity – other reserves — (6,910,256) (6,910,256) Deferred tax asset/(liability) on valuation gain or loss — 1,934,871 1,934,871 Total recognized gains and losses 7,993,453 2,736,070 5,257,383 Issue of shares 24,527,092 — 24,527,092 Share based payments 687,459 — 689,459 Closing equity 83,156,321 8,245,515 91,401,836

172 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Consolidated Income Statement

For the year ended 31 December 2005 Effect of transition UK GAAP to IFRS IFRS US$ US$ US$ Revenue 17,574,440 — 17,574,440 Cost of sales Production costs (3,247,610) — (3,247,610) Depletion (1,562,933) 732,500 (830,433) Decommissioning charge (57,779) — (57,779) Gross profit 12,706,118 732,500 13,438,618 Other operating income — — — Administrative expenses (4,688,985) (272,675) (4,961,660) Operating profit 8,017,133 459,825 8,476,958 Interest and investment income 890,096 — 890,096 Finance costs (361,204) — (361,204)

Profit on ordinary activities before taxation 8,546,025 459,825 9,005,850 Tax on profit on ordinary activities (3,101,052) (112,592) (3,213,644) Profit attributable to the equity shareholders of the parent company 5,444,973 347,233 5,792,206 Earnings per share Basic 0.11 0.01 0.12 Diluted 0.11 0.01 0.12

173 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Consolidated Balance Sheet

At 31 December 2005 Effect of transition UK GAAP to IFRS IFRS US$ US$ US$ Assets Non-current assets Intangible assets – exploration 9,547,305 6,634,972 16,182,277 Property, plant and equipment 11,395,296 (7,028,399) 4,366,897 Intangible assets – others — 147,510 147,510 Investment 2,218,122 15,750,130 17,968,252 23,160,723 15,504,213 38,664,936 Current assets Inventories 349,929 — 349,929 Deferred tax asset 745,000 (745,000) — Trade and other receivables 4,343,755 — 4,343,755 Cash and cash equivalents 31,234,376 — 31,234,376 36,673,060 (745,000) 35,928,060 Total assets 59,833,783 14,759,213 74,592,996 Liabilities Current liabilities Trade and other payables (5,267,588) — (5,267,588) (5,267,588) — (5,267,588) Non-current liabilities Provisions for liabilities and charges (1,863,720) — (1,863,720) Provision for deferred tax (2,754,158) (3,777,628) (6,531,786) (4,617,878) (3,777,628) (8,395,506) Total liabilities (9,885,466) (3,777,628) (13,663,094) Net assets 49,948,317 10,981,585 60,929,902 Equity Called-up share capital 520,467 — 520,467 Share premium account 28,507,954 — 28,507,954 Shares to be issued 252,634 — 252,634 Other reserves — 11,340,094 11,340,094 Retained earnings 20,667,262 (358,509) 20,308,753 Total equity 49,948,317 10,981,585 60,929,902

174 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Consolidated Cash Flow Statement

For the year ended 31 December 2005 Effect of transition UK GAAP to IFRS IFRS US$ US$ US$ Operating activities Cash flow generated by operations 11,044,390 (272,675) 10,771,715 Taxation paid (972,329) (972,329) Net cash from operating activities 10,072,061 (272,675) 9,799,386 Investing activities Purchase of intangible assets – exploration (7,735,427) 272,675 (7,462,752) Purchase of intangible fixed assets – others — (163,072) (163,072) Purchase of property, plant and equipment 1,014,104 163,072 1,177,176 Purchase of other fixed assets (458,012) — (458,012) Net cash used in investing activities (7,179,335) 272,675 (6,906,660) Financing activities Interest and investment income 653,002 — 653,002 Finance costs (304,954) — (304,954) Issue of shares 20,772,691 — 20,772,691 Repayment of bank loan (1,861,251) — (1,861.251) Net cash provided in financing activities 19,259,488 — 19,259,488 Net increase/(decrease) in cash and cash equivalent 22,152,214 — 22,152,214 Cash and cash equivalent at beginning of the year 9,082,162 — 9,082,162 Cash and cash equivalent at the end of the year 31,234,376 — 31,234,376

175 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

Consolidated Statement of Changes in Equity

For the year ended 31 December 2005 Effect of transition UK GAAP to IFRS IFRS US$ US$ US$ Opening equity 23,478,019 4,668,585 28,416,604 Profit for the year 5,444,973 347,233 5,792,206 Valuation gain/(loss) transferred to equity – other reserves — 8,285,787 8,285,787 Deferred tax asset/(liability) on valuation gain or loss — (2,320,020) (2,320,020) Total recognized gains and losses 5,444,973 6,313,000 11,757,973 Issue of shares 20,772,691 — 20,772,691 Share based payments 252,634 — 252,634 Closing equity 49,948,317 10,981,585 60,929,902

176 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

NOTES TO RECONCILIATIONS FROM UK GAAP TO IFRS FOR YEARS ENDED 31 DECEMBER 2006 AND 2005 The following notes reconcile the UK GAAP financial statements, with the consolidated financial statements prepared under IFRS.

Consolidated Income Statement i) Pre-exploration write offs Under IFRS 6, costs incurred prior to the legal rights to explore an area may no longer be capitalized as exploration assets whereas under UK GAAP all costs incurred prior to having obtained the license rights were included within intangible fixed assets. Accordingly, the pre-exploration costs incurred by Hardy totalling US$272,675 have been written-off against the income statement during 2005. ii) Loss on sale of entity and asset The loss on sale of the Sanganpur field (part of India cost pool) was capitalized under UK GAAP in 2004 for US$282,682. It was then reversed and charged as an expense under IFRS against retained earnings at 1 January 2006. Likewise, a wholly owned subsidiary of Heramec Limited was sold in the year 2004 and the resulting loss of US$423,060 was capitalized under India cost pool as tangible fixed assets and depleted. Under IFRS the loss on sale of entity has been charged against the retained earnings at 1 January 2006. iii) Depletion Under UK GAAP costs carried within each regional cost pool, which may contain a number of individual fields, were depleted on a unit of production basis by reference to that cost pool. Under IFRS costs are still depleted on a unit of production basis but by reference to specific fields. Under UK GAAP, unsuccessful exploration costs were transferred from intangible fixed assets to tangible fixed assets and depleted accordingly. Under IFRS, the unsuccessful exploration costs are capitalized as intangible fixed assets pending determination of whether or not commercial reserves exist. As a result, the depletion charge for the year 2006 and 2005 has been reduced by US$3,184,503 and US$732,500 respectively. iv) Taxation There is no impact on current tax. Deferred taxation has been adjusted to account for the impact of reduction in depletion, and the expensing of pre-exploration costs for the years 2006 and 2005.

Consolidated Balance Sheets i) Intangible assets — exploration Under UK GAAP, intangible fixed assets represented pre-license acquisition costs and exploration and evaluation (‘‘E&E’’) costs of individual license interests held outside the depreciable cost pools pending determination of commerciality. Under IFRS, intangible assets have been adjusted to write off cumulative pre-license acquisition costs of US$272,675 relating to the Nigeria cost pool, which was capitalized in intangible assets during 2005. ii) Property, plant and equipment Under UK GAAP, tangible fixed assets comprised of oil and gas properties for which the existence or otherwise of commercial reserves had been established, recorded by reference to the geographic cost pools such as India and Nigeria. This caption also included certain exploration and evaluation expenditure incurred within the cost pools and other fixed assets, including non oil and gas specific plant and equipment, office furniture and IT equipment. Under UK GAAP, the cost of dry holes of exploration blocks pending determination of commerciality of reserves have been capitalized and included in the tangible fixed assets in the respective cost pools. Under IFRS, the cost of dry holes of exploration blocks pending determination of commerciality

177 HARDY OIL AND GAS PLC Notes to the Consolidated Financial Statements For the year ended 31 December 2006

are capitalized under Intangible cost — exploration and are not depleted. Accordingly, under IFRS an amount of US$6,907,647 was transferred to Intangible assets — exploration from tangible fixed assets at 1 January 2006. Likewise, an amount of US$26,792,975 was transferred from tangible fixed assets to intangible assets — exploration in 2006. Under UK GAAP, the loss on sale of asset and the loss on sale of wholly owned subsidiary undertaking amounting to US$705,742 were capitalized as tangible fixed assets in 2004 and were also considered for charging depletion. Under IFRS, the net cost included in tangible fixed assets of US$631,927 (net of depletion) is written-off against retained earnings at 1 January 2006. iii) Investment Under UK GAAP, the investment in publicly traded securities are held at cost. Under IFRS, such investments are recognized at fair values based upon quoted market prices on balance sheet dates. As a result, the carrying value of investment has been increased by US$15,750,130 at 31 December 2005 and by US$8,839,874 at 31 December 2006. Deferred tax has been provided on such unrealized gain on investment as of January 1 2006 and 31 December 2006 respectively. Net gains at 31 December 2005 and 31 December 2006 have been directly credited to equity — other reserves. iv) Site restoration deposit As at 31 December 2006, an amount of US$2,784,660 was deposited with State Bank of India as a site restoration fund. This amount was included in cash and cash equivalents and is now transferred to site restoration deposit under IFRS as at 31 December 2006. v) Provision for deferred taxation Consequential changes have been made to the provision for deferred taxes at 31 December 2005 and 31 December 2006 as a result of writing off pre exploration expenditures, reducing depletion and reflecting investment at fair value. a) Consolidated Cash Flow Statement Cash flow statements prepared under IAS 7 presents the cash flows in three categories: operating activities, investing activities and financing activities, which are fewer than the categories under UK GAAP. Other than the reclassification and the movement of deposit of site restoration deposit from cash and cash equivalent, no other material changes were made. Pre-license costs were shown within ‘‘capital expenditure’’ under UK GAAP. Since such costs are being expensed under IFRS, they have been classified within operating cash flows under IFRS. Purchases of software was taken under tangible fixed assets under UK GAAP have been reclassified to purchases of intangible assets — others.

178 SECTION C

FINANCIAL INFORMATION FOR THE YEARS ENDED 31 DECEMBER 2005 AND 31 DECEMBER 2004 PREPARED IN ACCORDANCE WITH UNITED KINGDOM GENERALLY ACCEPTED ACCOUNTING STANDARDS (UK GAAP) The following is the full text of a report on Hardy Oil and Gas plc from Horwath Clark Whitehill LLP, as reporting accountants: The Board of Directors Hardy Oil and Gas plc 15-19 Athol Street Douglas Isle of Man IM1 1LB The Directors Arden Partners plc Nicholas House 3 Laurence Pountney Hill London EC4R 0EU 15 February 2008 Dear Sirs

Hardy Oil and Gas plc We report on the financial information set out Section C of part 5 of the prospectus dated 15 February 2008 of Hardy Oil and Gas plc (the ‘‘Company’’ and, together with its subsidiaries, the ‘‘Group’’) (the ‘‘Prospectus’’). This financial information has been prepared for inclusion in the Prospectus on the basis of the accounting policies set out in note 1. This report is required by Annex I item 20.1 of the Prospectus Directive Regulation and is given for the purpose of complying with that requirement and for no other purpose.

Responsibilities The Directors of Hardy Oil and Gas plc are responsible for preparing the financial information on the basis of preparation set out in note 1 to the financial information and in accordance with United Kingdom Generally Accepted Accounting Standards. It is our responsibility to form an opinion as to whether the financial information gives a true and fair view, for the purposes of the Prospectus, and to report our opinion to you. Save for any responsibility arising under Prospectus Rule 5.5.3R(2)(f) to any person as and to the extent there provided, to the fullest extent permitted by law we do not assume any responsibility and will not accept any liability to any other person for any loss suffered by any such other person as a result of, arising out of, or in accordance with this report or our statement, required by and given solely for the purposes of complying with Annex I item 23.1 of the Prospectus Directive Regulation, consenting to its inclusion in the Prospectus.

179 Opinion In our opinion, the financial information gives, for the purposes of the Prospectus, a true and fair view of the state of affairs of the Group as at 31 December 2005 and 31 December 2004 and of its profits, cash flows and other recognized gains and losses for the years ended 31 December 2005 and 31 December 2004 in accordance with the basis of preparation set out in note 1 and in accordance with United Kingdom Generally Accepted Accounting Standards.

Horwath Clark Whitehill LLP Chartered Accountants

180 HARDY OIL AND GAS PLC Group Profit and Loss Account For the year ended 31 December 2005

2005 2004 Notes $ $ Turnover 2 17,574,440 13,719,650 Cost of sales Production costs (2,951,270) (3,002,584) (Decrease)/increase in stock (296,340) 250,915 Depletion (1,562,933) (1,464,637) Decommissioning charge (57,779) (7,770) Gross profit 12,706,118 9,495,574 Administrative expenses (4,688,985) (2,419,096) Operating profit 3 8,017,133 7,076,478 Income from other fixed asset investments 165,570 108,502 Interest receivable and similar income 6 724,526 122,931 Interest payable and similar charges 7 (361,204) (275,374) Profit on ordinary activities before taxation 8,546,025 7,032,537 Tax on profit on ordinary activities – current 8 (318,894) (275,706) – deferred 8 (2,782,158) (3,298,000) (3,101,052) (3,573,706) Profit for the financial year 5,444,973 3,458,831

Earnings per ordinary share – basic 9 0.11 0.10 – diluted 9 0.11 0.09

Profit and Loss Account contains all the gains and losses recognised in the current year and previous year. The notes on pages 185 to 197 form an integral part of these financial statements.

181 HARDY OIL AND GAS PLC Reconciliation of Movements in Group Shareholders’ Funds For the year ended 31 December 2005

2005 2004 $ $ Profit for the financial year 5,444,973 3,458,831 New share capital subscribed 20,772,691 1,788,410 Shares to be issued 252,634 — Net addition to shareholders’ funds 26,470,298 5,247,241 Opening shareholders’ funds 23,478,019 18,230,778 Closing shareholders’ funds 49,948,317 23,478,019

The notes on pages 185 to 197 form an integral part of these financial statements.

182 HARDY OIL AND GAS PLC Group Balance Sheets As at 31 December 2005

2005 2004 Notes $ $ Fixed assets Intangible assets 10 9,547,305 8,719,525 Tangible assets 11 11,395,296 6,179,126 Investments 12 2,218,122 2,218,122 23,160,723 17,116,773 Current assets Stocks 349,929 646,269 Deferred tax asset 8 745,000 773,000 Debtors 14 4,343,755 2,740,896 Cash at bank and in hand 31,234,376 9,082,162 36,673,060 13,242,327 Creditors: amounts falling due within one year 15 (5,267,588) (5,585,081) Net current assets 31,405,472 7,657,246 Total assets less current liabilities 54,566,195 24,774,019 Provisions for liabilities and charges 16 (1,863,720) (1,296,000) Deferred tax liability 8(a) (2,754,158) — Net assets 49,948,317 23,478,019 Capital and reserves Called-up share capital 18 520,467 4,111 Share premium 20 28,507,954 8,251,619 Shares to be issued 19 252,634 — Profit and loss account 20,667,262 15,222,289 Equity shareholders’ funds 49,948,317 23,478,019

The notes on pages 185 to 197 form an integral part of these financial statements.

183 HARDY OIL AND GAS PLC Group Statement of Cash Flows For the year ended 31 December 2005

2005 2004 Notes $ $ Net cash inflow from operating activities 21 11,044,390 6,723,755

Returns on investments and servicing of finance Income from other investments 165,570 108,502 Interest received 487,432 122,931 Interest paid (304,954) (348,478) Net cash inflow from return on investments and servicing of finance 348,048 (117,045) Taxation (972,329) (1,706) Capital expenditure and financial investment Expenditure on exploration assets (7,735,427) (1,401,134) Expenditure on development/producing assets 1,014,104 (2,930,605) Purchase of other fixed assets (458,012) (55,787) Proceeds from disposal of interests in development assets — 280,000 Proceeds from disposal of subsidiary undertakings — 767,597 Net cash outflow from capital expenditure and financial investment (7,179,335) (3,339,929) Net cash inflow before financing 3,240,774 3,265,075 Financing Issue of shares 20,772,691 1,788,410 Repayment of bank loan (1,861,251) (441,484) Repayment of unsecured loan — (1,000,000) 18,911,440 346,926

Increase in cash for the year 22,152,214 3,612,001

The notes on page 185 to 197 form an integral part of these financial statements.

184 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

1. ACCOUNTING POLICIES The following accounting policies have been applied in preparation of consolidated financial statement of Hardy Oil and Gas plc. a) Accounting convention The accounts are prepared under the historical cost convention. b) Accounting standards Hardy prepares its accounts in accordance with the accounting standards of United Kingdom and in accordance with the Statement of Recommended Practice (‘‘SORP’’) issued by the Oil Industry Accounting Committee, United Kingdom; Accounting for Oil and Gas Exploration, Development, Production and Decommissioning Activities. c) Basis of Consolidation The consolidated accounts include the results of Hardy Oil and Gas plc, and its subsidiary undertakings. The consolidated profit and loss account and cash flow statement include the results and cash flows of subsidiary undertakings up to the date of disposal. The group conducts the majority of its exploration, development and production through unincorporated joint arrangements with other companies. The accounts reflect the group’s share of production and costs attributable to its participating interests under the proportional consolidation method. d) Turnover Turnover represents the sale value of the Group’s share of oil (excluding profit oil share of government) sold in the year, tariff, and the income from technical services to third parties if any. e) Fixed assets Hardy follows the full cost method of accounting for oil and gas assets. Under this method, all expenditure incurred in connection with and directly attributable to the acquisition, exploration, appraisal and development of oil and gas assets, interest payable and exchange differences incurred on borrowings directly attributable to development projects if any is capitalized in two geographical cost pools: India and Nigeria. Exploration assets comprise the pre-license, license acquisition, exploration and appraisal costs relating either to unevaluated properties or properties awaiting further evaluation. When a decision to develop these properties has been taken or there is evidence of impairment, the costs are transferred as development cost to the cost pools within ‘Development/producing assets’ when the commercial reserves attributable to the underlying asset have been established. Further expenditure on fixed assets in the production phase is capitalized where future economic benefit is enhanced. In case of any disposal of oil and gas assets, net proceeds from any such disposal are credited against the previously capitalized costs. In the case of disposal of subsidiary undertaking, net proceeds represent the net book value of the assets sold together with the gain or loss arising on disposal of that subsidiary. f) Depletion, impairment and depreciation

i) Depletion Hardy depletes expenditure on oil and gas production and development on a unit of production basis, based on proved and probable reserves.

185 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

ii) Impairment

Exploration assets are reviewed regularly for indications of impairment, if any, where circumstances indicate that the carrying value might not be recoverable. In such circumstances if the exploration asset has a corresponding development/producing cost pool, then the exploration costs are transferred to the cost pool and are written off on a unit of production basis through the depletion charge. In cases where no such development/producing cost pool exists, the impairment of exploration costs is charged to the profit and loss account. Impairment reviews on development/producing oil and gas assets are carried out for each cost pool on each year by comparing the net book value of the pool with the associated discounted future cash flows. If the net book value is higher, then the difference is written off to the profit and loss account as impairment.

iii) Depreciation

Fixed assets, other than oil and gas assets, are depreciated over their expected useful economic lives as follows:

Annual Rate (%) Depreciation Method Leasehold improvements over lease period straight line Furniture and fixtures 20% straight line IT and computers 33% straight line Other equipments 20% straight line g) Decommissioning

At the end of the producing life of a field, costs are to be incurred in removing, decommissioning facilities, plugging and abandoning the wells. Decommissioning costs are estimated and stated at an amount representing the costs, which would be incurred should decommissioning occur at the balance sheet date and the estimates are reassessed on each year. The decommissioning asset is included within fixed assets with the cost of the related assets installed and are adjusted for any revision to the decommissioning costs and the provision thereof. The amortization of the asset, calculated on a unit of production basis based on proved and probable reserves, is shown as ‘‘Decommissioning charge’’ in the profit and loss account. h) Foreign currencies

Hardy maintains the accounts of the Company and all subsidiary undertakings in US dollars. Foreign currency transactions are accounted for at the exchange rate ruling on the date of the transaction. At the year end all foreign currency assets are restated at the average of the buying and the selling exchange rates prevailing at the balance sheet date. Exchange difference arising out of actual payments/realizations and from the year end restatement referred to above are dealt with the in the profit and loss account.

Rate of exchanges were as follows:

31 December 31 December 2005 2004 £ to US $ 1.7191 1.9485 US $ to Indian Rupees 45.1300 43.6800

186 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005 i) Deferred taxation

Deferred tax is recognized in respect of all timing differences that have originated but not reversed at the balance sheet date where transactions or events have occurred at that date that will result in an obligation to pay more or a right to pay less or to receive more tax.

Deferred tax assets are recognized only the extent that the Directors consider that it is more likely than not there will be suitable taxable profits from which the future reversal of the underlying timing differences can be deducted.

Deferred tax is measured on an undiscounted basis at the tax rates that are expected to apply in the periods in which timing differences reverse, based on tax rates and laws enacted or substantively enacted at the balance sheet date. j) Leasing commitments

Rental charges or charter hire charges payable under operating leases are charged to the profit & loss account as part of production expenses over the lease term. k) Share based payments

Hardy issues share options to directors and employees, which are measured at fair value at the date of grant. The fair value of the equity settled options determined at the grant date is expensed on a straight line basis over the vesting period based on the actual number of shares vested in the accounting period. In performing the valuation of these options, only conditions other than the market conditions were taken into account. Fair value is measured by use of a binomial model and the assumed expected life of the share options is based on estimates of management considering non-transferability, exercise restrictions, and expected behavioural considerations.

2. TURNOVER AND SEGMENTAL ANALYSIS

2005 2005 2004 2004 $ $ $ $ Turnover India London India London Continuing operations – Oil sales 21,308,877 — 13,447,529 — – Profit oil to government (3,983,854) — (790,518) — – Other income 2,641 246,776 17,955 1,044,684 17,327,664 246,776 12,674,966 1,044,684

The Directors do not consider there to be more than one class of business or geographic segment. Other income relates to technical services to third parties, overhead recovery from joint venture operations and miscellaneous receipts if any. Turnover arises from sale of oil produced from the contract area CY-OS-90/1-India and the turnover by destination is not materially different from the turnover by origin.

187 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

3. OPERATING PROFIT

Operating profit is stated after charging:

2005 2004 $ $ Depreciation 82,393 65,697 Depletion 1,562,933 1,464,637 Decommissioning 57,779 7,770 Operating lease costs – plant & machinery 1,887,686 1,733,202 – land & buildings 162,450 193,741 Auditors’ remuneration – company UK 34,081 22,786 – other assurance UK 209,730 — – subsidiaries—overseas 29,310 20,469

The Group has a policy in place for the award of non-auditor work to the auditors, which requires approval of the Audit Committee. Audit fees to overseas subsidiaries are payments made to overseas auditors other than the Company auditors.

4. STAFF COSTS

2005 2004 $ $ Wages and salaries 1,956,093 1,563,188 Social security costs 93,662 60,757 Other pension costs 9,410 12,099 2,059,165 1,636,044

Staff costs include Executive Director’s salary, fees and benefits and are shown gross before amounts recharged to joint ventures. The weighted average monthly number of employees, including directors and individuals employed by the Group working on joint venture operations are as follows:

2005 2004 Employees Employees Management and administration 18 17 Operations 26 23 44 40

5. DIRECTORS’ EMOLUMENTS

Details of remunerations are set out in as follows:

2005 2004 $ $ Directors’ emoluments 577,153 545,376 Highest paid 273,264 272,927

Directors’ emoluments include $4,807 towards pension contribution to one of the director’s pension scheme. The aggregate gain made by the directors pursuant to the exercise of the share option during the year was $10.60 million and the gain of the highest paid director was $6.44 million.

188 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

6. INTEREST RECEIVABLE AND SIMILAR INCOME 2005 2004 $ $ Bank interest 724,526 59,279 Other interest — 63,652 724,526 122,931

7. INTEREST PAYABLE AND SIMILAR CHARGES 2005 2004 $ $ Bank loan and overdraft interest 361,204 254,224 Other finance charges — 21,150 361,204 275,374

8. TAXATION a) Analysis of taxation charge in year

2005 2004 $ $ Current tax charge UK Corporation Tax — — Foreign tax India Minimum alternate tax on profits for the year 497,894 179,000 Previous year provision reversed (179,000) — Dividend tax — 1,706 318,894 180,706 Foreign tax USA Alternate minimum tax on profits for the year — 95,000 — 95,000 Total current tax charge 318,894 275,706 Deferred tax charges 2,782,158 3,298,000 Tax on profit on ordinary activities 3,101,052 3,573,706 Deferred tax charge: Origination and reversal of timing difference 2,782,158 3,298,000 Deferred tax charges 2,782,158 3,298,000

Deferred tax analysis: $$ Differences between accumulated depletion and depreciation and capital allowances (4,183,000) (2,492,000) Other timing differences 591,842 546,000 Tax losses 1,582,000 2,719,000 Deferred tax (liability)/asset (2,009,158) 773,000 Disclosed as: Deferred tax (liability) (2,754,158) — Deferred tax asset 745,000 773,000

189 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005 b) Factors affecting tax charge for year

2005 2004 $ $ Profit on ordinary activities before tax 8,798,659 7,032,537 Profit on ordinary activities before tax multiplied by the rate of tax in UK of 30% 2,639,598 2,109,761 Mineral extraction and research allowances in excess of depreciation and utilisation of tax losses (2,639,598) (2,109,761) Effects of non taxable income — — Foreign tax on overseas income 318,894 275,706 Total current tax charge 318,894 275,706 c) Indian operation of the Group was subject to a tax rate of 41.82 per cent., which was higher than UK and US corporations tax rates. As the double taxation avoidance agreement exists the Group should entitle to get the treaty benefit for the taxes paid in India. Base on the current expenditure plans, the Group anticipates that the tax allowances will continue to exceed the depletion charge of each year though the timing of related tax relief is uncertain.

9. EARNINGS PER ORDINARY SHARE

The earnings per ordinary share is calculated on a profit of $5,444,973 (2004: $3,458,831) on a weighted average of 47,871,777 ordinary shares (2004: 34,962,090). The weighted average shares are arrived after giving impact to bonus shares issued at the rate of 99 shares for one share held in May 2005.

The diluted earnings per ordinary share was calculated on a profit of $5,444,973 (2004: $3,458,831) on a weighted average of 50,588,876 ordinary shares (2004: 40,362,090). The weighted average shares are arrived after giving impact to bonus shares issued at the rate of 99 shares for each share in May 2005 and dilutive potential ordinary shares of 2,717,099 (2004: 5,400,000) relating to share options.

10. INTANGIBLE ASSETS

Oil and gas exploration assets

India Nigeria Total $ $ $ Costs and net book value At 1 January 2005 8,504,685 214,840 8,719,525 Additions 6,854,441 880,986 7,735,427 Deletions – transfer to tangible asset (6,907,647) — (6,907,647) At 31 December 2005 8,451,479 1,095,826 9,547,305 At 31 December 2004 8,504,685 214,840 8,719,525

190 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

11. TANGIBLE ASSETS

Oil and gas assets represent interest in producing oil and gas assets falling under the Indian cost pool. There is no oil and gas tangible assets currently in the Nigerian cost pool. Other tangible assets consist of office furniture, computers, workstations and office equipment.

Oil and gas development/producing assets

Other fixed Total Oil and gas assets assets $ $ $ Costs and net book value At 1 January 2005 24,369,807 2,530,139 26,899,946 Addition (446,384) 464,000 17,616 Transfer from intangible asset 6,907,647 — 6,907,647 Disposals — (543,436) (543,436) At 31 December 2005 30,831,070 2,450,703 33,281,773 Depletion, depreciation and amortisation At 1 January 2005 18,261,142 2,459,678 20,720,820 Charge for the year 1,620,712 82,393 1,703,105 Disposals — (537,448) (537,448) At 31 December 2005 19,881,854 2,004,623 21,886,477 Net book value at 31 December 2005 10,949,216 446,080 11,395,296 Net book value at 31 December 2004 6,108,665 70,461 6,179,126

12. INVESTMENTS

2005 2004 $ $ Other investment 2,218,122 2,218,122

Other investment represents an investment in 4,993,271 equity shares of an Indian company — Hindustan Oil Exploration Company Limited — listed on National Stock Exchange and Bombay Stock Exchange in India. The market value of the shares as at 31 December 2005 was $17.97 million based on Rs162.40 per share quoted at Bombay Stock Exchange on 30 December 2005 converted at an exchange rate of one $ per Rs45.13. (2004: $9.68 million at a price of Rs84.70 per share at an exchange rate of 1$ = Rs43.68).

13. SUBSIDIARY COMPANIES

a. Hardy Exploration & Production (India) Inc, a wholly owned subsidiary incorporated under the laws of the State of Delaware, United States of America.

b. Hardy Oil (Africa) Limited, a wholly owned subsidiary registered under the laws of the Isle of Man.

c. Hardy Oil Nigeria Limited, a wholly owned subsidiary of Hardy Oil (Africa) Limited registered under the laws of Nigeria.

The above subsidiaries are included in the Group consolidation.

191 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

14. DEBTORS

2005 2004 $ $ Trade debtors 2,308,459 1,514,155 Other debtors 486,548 1,181,162 Advance tax paid in India 379,435 — Prepayments and accrued income 1,169,313 45,579 4,343,755 2,740,896

Other debtors include $35,000 due from key employees of the subsidiary undertaking. 15. CREDITORS — AMOUNTS FALLING DUE WITHIN ONE YEAR

2005 2004 $ $ Secured bank loan — 1,805,001 Trade creditors 2,279,086 1,230,994 Other creditors 1,036,705 724,835 Taxation — 274,000 Accruals 1,951,797 1,550,251 5,267,588 5,585,081

Transactions with directors: Included within other creditors are the following amounts due to the directors:

2005 2004 $ $ E.P. Mortimer 30,000 — Pradip Shah 30,000 — Carol Bell 5,000 —

The balance due at the year-end represented the maximum amount due during the year. 16. PROVISIONS Provisions for liabilities and charges

Decommissioning $ At 1 January 2005 1,296,000 Additional cost for decommissioning 567,720 At 31 December 2005 1,863,720

The Decommissioning provision has been made using current prices and with the existing technology. Decommissioning costs are expected to be incurred between 2016 and 2019. 17. FINANCIAL INSTRUMENTS Hardy is financing its operations through a mixture of retained earnings, additional equity and bank borrowings if required. When substantial funds are required for acquisition, exploration and development of projects, the Board will review the appropriateness of using equity, debt and/or project financing. Hardy’s principle financial instruments are cash and short-term deposits and these instruments are only for the purpose of meeting its requirement for operations. Hardy takes exemption under FRS 13 for short-term debtors and creditors and therefore, exempted for numerical disclosures except foreign currency risk disclosures.

192 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

Hardy’s main risks arising from financial instruments are foreign currency risk, commodity price risks and liquidity risk. Hardy’s policy of managing the foreign currency risk, commodity price risk and liquidity risk are as follows:

Foreign currency risk The Group reports are in US dollars and the majority of its business is conducted in US dollars. All revenues from oil sales are received in $ and all costs except a small portion towards expenses at London office are incurred in $. In case of currency exposure other than US$, a portion of the cash is kept in deposit in other currencies to meet payments as required. No forward exchange contracts were entered into during the year.

Commodity price risk The product prices are naturally hedged to the pricing mechanism in place as per the contract entered in to with the buyer. The price of each off-take is based on the 30 days average Brent price of the crude 14 days before and 15 days after the date of crude off-take. During the year no hedging contracts have been entered into and no outstanding hedging contract is in place either at the beginning or at the end of the financial year.

Liquidity risk The Group deposits the surplus cash on short-term deposits ensuring sufficient liquidity to meet the Group’s expenditure requirements. The Company has no outstanding loan obligations at the end of the year. a) Maturity of financial liabilities The financial liabilities and its maturity as at 31 December 2005 are as follows:

2005 2004 $ $ In more than two years but not more than five years — — In more than five years 1,863,720 1,296,000

The Group did not have any fixed maturity and interest bearing financial liabilities as at 31 December 2005. b) Interest rate risk profile of financial assets

The interest rate risk of the financial assets of the group as at 31 December 2005 is as follows:

Fixed rate Floating rate Financial asset – financial financial no interest was asset asset earned Total $ $ $ $ US Dollars 14,413,128 7,216,626 1,603,707 23,233,461 Pound Sterling 3,529,203 361,883 31,081 3,922,167 Indian Rupees 3,959,270 — 116,112 4,075,382 Nigerian Naira — — 3,366 3,366 21,901,601 7,578,509 1,754,266 31,234,376

Financial assets include cash, deposits, short-term investments if any and the floating interest rates are based on base rate of Bank of England.

193 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

The interest rate risk of the financial assets of the Group as at 31 December 2004 was as follows:

Fixed rate Floating rate Financial asset – financial financial no interest is asset asset earned Total $ $ $ $ US Dollars 1,600,000 5,279,646 1,209,978 8,089,624 Pound Sterling — 110,276 15,743 126,019 Indian Rupees 817,478 — 49,041 866,519 2,417,478 5,389,922 1,274,762 9,082,162

Financial assets include cash, deposits, short-term investments if any and the floating interest rates are based on base rate of Bank of England. c) Currency exposures

The currency exposures of the foreign currency monetary assets of the Group year ended 31 December 2005 are as follows:

Indian Pound Nigerian Rupees Sterling Naira Total $ $ $ $ $ 4,075,382 3,922,167 3,366 8,000,915

An amount of $564,153 was recognized as foreign exchange loss for the year 2005.

The currency exposures of the foreign currency monetary assets of the Group year ended 31 December 2004 were as follows:

Indian Pound Nigerian Rupees Sterling Naira Total $ $ $ $ $ 866,519 126,019 — 992,538

An amount of $182,584 was recognized as foreign exchange gain for the year 2004. d) Fair values of financial assets and financial liabilities

Fair values of Hardy’s financial assets and liabilities excluding short-term debtors and creditors are compared as follows:

Book Value Fair Value Book Value Fair Value 31 December 31 December 31 December 31 December 2005 2005 2004 2004 Primary financial instruments $ $ $ $ Provisions for decommissioning (1,863,720) (1,863,720) (1,296,000) (1,296,000) Fixed asset investments 2,218,122 17,968,252 2,218,122 9,682,465 Cash, short term bank deposits 31,234,376 31,234,376 9,082,162 9,082,162 31,588,778 47,338,908 10,004,284 17,468,627

194 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

18. SHARE CAPITAL

Number $0.01 Ordinary Shares ’000 Authorised ordinary shares At 1 January 2005 2,000 At 31 December 2005 200,000

$0.01 Ordinary Shares Allotted, issued and fully paid ordinary shares At 1 January 2005 411,096 Converted to redeemable preference shares (48,796) Bonus shares issued 41,213,700 Share options converted 54,000 Shares issued 10,416,667 At 31 December 2005 52,046,667

During the year the Company has converted 48,796 ordinary shares into redeemable preference shares at the same face value of equity shares and these shares were redeemed at $120 per share.

During the year a sum of $412,137 being the part of the amount standing to the credit of share premium account was capitalized and the Company has issued 41,213,700 new ordinary shares on 31 May 2005 at the rate of 99 new ordinary shares to every one ordinary share held.

During the year 10,416,667 ordinary shares having a face value of $0.01 were issued on 7 June 2005 at a price of £1.44 per share.

In addition, on 9 February 2006 additional equity of $24.55 million (£14.13 million after the expenses) was raised by way of placing 5,204,660 ordinary shares $0.01 each at a price of £2.83 ($4.92) per share. This capital will be used to meet Hardy’s ongoing working capital requirements.

19. SHARE BASED PAYMENTS

Share options have been granted to subscribe for ordinary shares, which are exercisable between 2005 to 2015 at prices ranging from £1.44 to £2.76. On 31 December 2005, there were 2,717,099 options outstanding.

The Company has an unapproved share option scheme for the directors and employees of the Group. Options are exercisable at the quoted market price of the Company’s shares on the date of grant. The options, vest in there equal portions on the first, second and third anniversary of the grant, providing the option holder is still employed by the Company. If the options are not exercised within a period of ten years from the date of grant the options stand expired.

Details of the share options outstanding during the year ended 31 December 2005 are as follows:

Number of Weighted options average price £ Outstanding at the beginning of the period — — Granted during the period 2,717,099 1.60 Outstanding at the end of the period 2,717,099 1.60 Exercisable at the end of the period — —

195 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

The aggregate of the estimated fair values of the options granted outstanding as on 31 December 2005 is $1,691,984. The inputs into the binomial model for computation of value of options are as follows:

Share price at date of grant varies from £1.44 to £2.76 Options exercise price at date of grant varies from £1.44 to £2.76 Expected volatility 8.00% Expected life from grant date 6 years Risk-free rate 4.15% Expected dividend Nil

The Group has recognised an expense of $267,471 towards equity settled share based payments. Equity shares to be issued are revalued at the exchange rate as at 31 December 2005 and the value of shares to be issued as at 31 December 2005 is $252,634.

20. RESERVES

Share Profit and Loss Premium Account $ $ At 1 January 2005 8,251,619 15,222,289 Redemption of preference shares (5,855,032) — Bonus shares (412,137) — Share options exercised 1,251,860 — Issue of shares 27,255,834 — Issue expenses (1,984,190) — Retained profit for the year — 5,444,973 At 31 December 2005 28,507,954 20,667,262

During the year 48,796 preference shares were redeemed at a price of $120 per share having the face value of $0.01 per share.

21. RECONCILIATION OF OPERATING PROFIT TO OPERATING CASH FLOWS

2005 2004 $ $ Operating profit 8,017,133 7,076,478 Depletion and depreciation 1,645,326 1,530,334 Decommissioning charge 57,779 7,770 Share based payment charges 252,634 — Increase in debtors (986,329) (1,713,155) Increase in creditors 1,761,507 145,592 Decrease/(increase) stocks (296,340) (323,264) Net cash inflow from operating activities 11,044,390 6,723,755

196 HARDY OIL AND GAS PLC Notes to the Accounts For the year ended 31 December 2005

22. NET FUNDS a) Analysis of net funds

At At 1 January Non cash 31 December 2005 Cash flows flows 2005 $ $ $ $ Cash at bank 9,082,162 22,152,214 — 31,234,376 Debts due within one year (1,805,001) 1,861,251 (56,250) — 7,277,161 24,013,465 (56,250) 31,234,376

Bank guarantees for $13,558,810 were issued to Government of India as a guarantee to ensure the fulfillment of the committed work program for the blocks CY-OS/2, GS-OSN-2000/1 and KG-DWN- 2001/1. In order to obtain the above bank guarantees, fixed deposits of Rs178, 681,861 ($3,959,270) were made in the bank and the deposits are held as margin money to the above bank guarantees. The fixed deposit of Rs147, 120,000 ($3,259,916) and other deposits of Rs31, 561,861($699,354) are interest bearing at the rates of 6.5 per cent. and 6.0 per cent. per annum respectively. b) Reconciliation of net cash flow to movement in net funds

2005 2004 $ $ Increase in cash in the year 22,152,214 3,612,001 Cash inflow from drawdown of debt financing 1,861,251 1,441,484 Change in net funds resulting from non-cash flows (56,250) (56,250) Net funds at beginning of year 7,277,161 2,279,926 Net funds at end of year 31,234,376 7,277,161

23. OTHER NON-CANCELABLE FINANCIAL COMMITMENTS Annual commitments under non-cancelable operating leases are as follows:

2005 2004 $ $ Land and buildings, expiring within: One year 203,477 159,025 Two to five years 141,341 159,025 After five years — — Other operating leases, expiring within: One year 1,767,330 1,767,330 Two to five years 1,007,136 1,767,330 After five years — —

Other operating lease commitments represent Hardy’s share of operating lease for floating production system entered into by unincorporated joint venture for its participating interest.

197 SECTION D

CAPITALISATION AND INDEBTEDNESS STATEMENT

Capitalisation and Indebtedness The capitalisation and indebtedness of the Group, extracted from the audited financial information contained in Part 6 of this document as at 30 September 2007 is set out below. In addition, the capitalisation of the Group as at 30 November 2007, extracted without adjustment from the unaudited management financial information of the Group, is also set out below.

At As at 30 September 30 November 2007 2007 US$ US$ Total current debt Guaranteed — — Secured —— Unguaranteed/unsecured — — —— Total current debt Guaranteed — — Secured —— Unguaranteed/unsecured — — —— Shareholders’ equity Share capital 622,625 622,625 Share premium account 93,101,579 93,101,579 Other reserves 9,921,602 11,853,483 103,645,806 105,577,687 Total 103,645,806 105,577,687

The above table does not include the carrying value for shares to be issued in connection with the grant of share options nor does it include retained earnings of Hardy.

Net indebtedness of the Group in the short and medium-long term as at 30 September 2007 and 30 November 2007 At As at 30 September 30 November 2007 2007 US$ US$ Cash 4,198,222 3,722,001 Cash equivalent (short term deposits) 29,225,946 29,134,934 Trading securities — — Liquidity 33,424,168 32,856,935 Current financial receivable 3,453,325 2,043,187 Current bank debt — — Current portion of non current debt — — Other current financial debt — — Current financial debt ——

Net current financial receivable 36,877,493 34,900,122

As at 30 November 2007, bank guarantees for $4,985,715 were issued to the Government of India.

198 PART 6 — ADDITIONAL INFORMATION

1. RESPONSIBILITY 1.1 The Company and its Directors (whose names appear on page 16 of this document) accept responsibility for the information contained in this document. To the best of the knowledge of the Company and the Directors (who have taken all reasonable care to ensure that such is the case), the information contained in this document is in accordance with the facts and contains no omission likely to affect its import.

2. THE COMPANY 2.1 The Company was incorporated in the Isle of Man on 26 September 1997 under the name of Jehan Energy Limited with registered number 087462C as a private company with limited liability under the Isle of Man Companies Acts 1931-1993. On 5 December 2001 the Company changed its name to Hardy Oil and Gas Limited. The Company was re-registered as a public limited company on 31 May 2005 and its name was changed to Hardy Oil and Gas plc. 2.2 The registered office of the Company is at 15-19 Athol Street, Douglas, Isle of Man IM1 1LB. The principal place of business of the Company in the UK is at Lincoln House 137-143 Hammersmith Road, London W13 0QL. The Company’s e-mail address is [email protected], its telephone number is +44 (0) 20 7471 9850 and its fax number is +44 (0) 20 7471 9851. 2.3 The principal legislation under which the Company currently operates is the Isle of Man Companies Acts 1931-2004 and the regulations made thereunder. The liability of members of the Company is limited. 2.4 The Ordinary Shares are in registered form and their ISIN code is GB00B09MB366. 2.5 The Company’s Ordinary Shares are admitted to trading on AIM under the symbol ‘‘HDY’’. Upon Admission, the admission of the Company’s Ordinary Shares to trading on AIM will be cancelled. 2.6 The Company has the following subsidiaries, all of which are wholly owned:

Date of Country of Registered Name Incorporation Incorporation Office

Hardy Exploration 21.02.1995 State of 1209 Orange Street, & Production Delaware, USA Wilmington, (India) Inc. New Castle, State of Delaware USA Hardy Oil (Africa) Limited 25.02.2004 Isle of Man 15-19 Athol Street, Douglas, Isle of Man IM1 1LB Hardy Oil Nigeria Limited* 24.01.2005 Republic of 11 Raymond Nigeria Njdeu Street, Ikoyi, Lagos, Nigeria

* 2 shares are held on trust for Hardy Oil (Africa) Limited by Mr Sharma and Mr Karra

3. SHARE CAPITAL 3.1 The Ordinary Shares have been created pursuant to the Acts. The authorised capital of the Company is US$2,000,000 divided into 200,000,000 Ordinary Shares. As at 31 December 2006 there were 57,252,994 issued and fully paid Ordinary Shares. As at the date of this document the issued share capital is 62,262,536 Ordinary Shares.

199 3.2 During the period covered by the historical financial information and up until 14 February 2008 (being the latest practicable date prior to the publication of this document), the following changes have been made to the issued share capital of the Company: 3.2.1 as at 31 December 2004 there were 411,096 Ordinary Shares in issue and fully paid; 3.2.2 on 15 February 2005 the Company converted 48,796 Ordinary Shares into preference shares of US$0.01 (the ‘‘Preference Shares’’) ranking pari passu with the then existing issued Ordinary Shares save that on a return of capital on a winding up or otherwise, the Preference Shares conferred upon the holders thereof the right to receive payment of the amount paid up thereon in priority in respect of the Ordinary Shares; 3.2.3 on 15 February 2005 each Preference Share was converted into a redeemeable preference share and then redeemed at a price of US$120 per redeemable preference share, representing US$0.01 nominal value and US$119.99 premium per redeemable preference share, the nominal value and the premium value being paid from the share premium account of the Company; 3.2.4 on 15 February 2005 the redeemable preference shares so redeemed were then cancelled; 3.2.5 on 31 May 2005 the Company increased its authorised share capital from US$20,000 to US$2,000,000 by the creation of an additional 198,000,000 Ordinary Shares; 3.2.6 on 31 May 2005, the Company made a bonus issue to shareholders of 41,213,700 Ordinary Shares fully paid up by capitalising the US$412,317 standing to the credit of the Company’s reserves; 3.2.7 on 7 June 2005 the Company issued 10,416,667 Ordinary Shares fully paid by way of a placing at a placing price of 144p per Ordinary Share; 3.2.8 on 9 February 2006 the Company issued 5,204,660 Ordinary Shares fully paid by way of a placing at a placing price of 283p per Ordinary Share; 3.2.9 on 10 July 2006, in order that Ordinary Shares may be issued and admitted to AIM upon the exercise of Options under the Share Option Scheme, the Company made a block admission to AIM for 1,000,000 Ordinary Shares to be admitted to AIM. Between 11 July 2006 and 10 July 2007 the Company issued 46,669 Ordinary Shares, fully paid, in respect of the exercise of Options and these were admitted to AIM under the block admission. Since 10 July 2007 no further Options have been exercised; 3.2.10 on 25 May 2007 the Company issued 4,964,540 new Ordinary Shares, fully paid by way of a placing at a placing price of 423p per Ordinary Share. 3.3 As at the date of this document there are outstanding Options to acquire 4,352,098 Ordinary Shares outstanding pursuant, to the Share Option Scheme, further details of which are provided in paragraphs 6 and 7.5 below. 3.4 As at the date of this document, no stand alone options have been granted by the Company. 3.5 Save as disclosed above: 3.5.1 since the date of incorporation of the Company no share or loan capital of the Company has been issued or agreed to be issued, or is now proposed to be issued, either for cash or for a consideration other than cash to any person; 3.5.2 no discounts, commissions, brokerages or other special terms have been granted by the Company in connection with the Placing or sale of any share or loan capital from the date of incorporation of the Company to the date of this document; 3.5.3 no share or loan capital of the Company is under option or has been agreed conditionally or unconditionally to be put under option. 3.6 Following the passing of a special resolution at the Company’s annual general meeting on 26 July 2007, the Company has authority to disapply the pre-emption provisions of the Articles and may issue up to 3,113,127 Ordinary Shares (representing 5 per cent. of the issued share capital as at 26 July 2007) on such terms as the Directors may determine.

200 4. MEMORANDUM OF ASSOCIATION The Companies Act 1986 (the ‘‘1986 Act’’) of the Isle of Man removed the need for the objects of a company incorporated in the Isle of Man after 1 June 1998 to be set out in the Memorandum of Association of the company by providing that the company has the capacity and the rights, powers and privileges of an individual, subject to the 1986 Act. As the Company is a company which was incorporated in the Isle of Man after 1 June 1988, the objects of the Company are not set out in its Memorandum of Association. Pursuant to the 1986 Act, however, the Company has had capacity and, subject to the 1986 Act, the rights, powers and privileges of an individual. Clause 4 of the Memorandum of Association of the Company provides that there are no restrictions on the exercise of the rights, powers and privileges of the Company, save for any which may be decided upon by special resolution of the Company in accordance with Section 6 of the 1986 Act.

5. ARTICLES OF ASSOCIATION 5.1 The following is a description of the rights attaching to the Ordinary Shares based on the Articles which have been adopted. The description does not purport to be complete and is qualified in its entirety by the full terms of the Articles. The Articles contain, inter alia, provisions to the following effect: 5.1.1 Voting rights Subject to the provisions of the Acts and to any special terms as to voting on which any shares may have been issued or may for the time being be held and to any suspension or abrogation of voting rights pursuant to the Articles, at any general meeting every member who (being an individual) is present in person or (being a corporation) is present by a duly authorised representative, not being himself a member entitled to vote, shall on a show of hands have one vote and on a poll every member present in person or by proxy or (being a corporation) by a duly authorised representative shall have one vote for each share of which he is the holder. 5.1.2 Variation of rights Subject to the provisions of the Acts, if at any time the share capital of the Company is divided into shares of different classes any of the rights for the time being attached to any share or class of shares in the Company (and notwithstanding that the Company may be or be about to be in liquidation) may (unless otherwise provided by the terms of issue of the shares of that class) be varied or abrogated in such manner (if any) as may be provided by such rights or, in the absence of any such provision, either with the consent in writing of the holders of not less than three quarters in nominal value of the issued shares of the class or with the sanction of an extraordinary resolution passed at a separate general meeting of the holders of shares of the class duly convened and held as provided in the Articles. This paragraph shall apply also to the variation or abrogation of the special rights attached to some only of the shares of any class, as if each group of shares of the class differently treated formed a separate class, the separate rights of which are to be varied. Subject to the terms of issue or the rights attached to any shares, the rights or privileges attached to any class of shares shall be deemed not to be varied or abrogated by the Board resolving that a class of shares is to become or to cease to be a participating security (a ‘‘Participating Security’’) within the meaning of the Uncertificated Regulations. 5.1.3 Alteration of capital The Company in general meeting may from time to time by ordinary resolution: (a) increase its share capital by such sum to be divided into shares of such amount as the resolution prescribes; (b) consolidate and/or divide, re-designate or convert all or any of its share capital into shares of larger or smaller nominal amount, or into different classes of shares than its existing shares; (c) cancel any shares which at the date of the passing of the resolution have not been taken or agreed to be taken by any person and diminish the amount of its share capital by the amount of the shares cancelled; and

201 (d) subject to the provisions of the Acts, sub-divide its shares or any of them into shares of smaller nominal value than is fixed by the Memorandum of Association of the Company and may by such resolution determine that as between the shares resulting from the sub-division, one or more of the shares may, as compared with the others, have any such preferred, deferred or other special rights or be subject to any such restrictions as the Company has power to attach to unissued or new shares but so that the proportion between the amount paid up and the amount (if any) not paid up on each reduced share shall be the same as it was in the case of the share from which the reduced share is derived. Subject to the provisions of the Acts and to any rights for the time being attached to any shares, the Company may by special resolution reduce its share capital, any capital redemption reserve, any share premium account or any undistributable reserve in any manner. Subject to the provisions of the Acts and to any rights for the time being attached to any shares, the Company may enter into any contract for the purchase of any of its own shares of any class (including any redeemable shares) and any contract under which it may, subject to any conditions, become entitled or obliged to purchase all or any of such shares. Any shares to be so purchased may be selected in any manner whatsoever provided that if at the relevant date proposed for approval of the proposed purchase there shall be in issue any shares of a class entitling the holders to convert into equity share capital of the Company then no such purchase shall take place unless it has been sanctioned by a special resolution passed at a separate general meeting (or meetings if there is more than one class) of the holders of the class of convertible shares. 5.1.4 Transfer of Shares Each member may transfer all or any of his shares in the case of certificated shares by instrument of transfer in writing in any usual form or in any form approved by the Board or in the case of uncertificated shares without a written instrument in accordance with the Uncertificated Regulations. Any written instrument shall be executed by or on behalf of the transferor and (in the case of a transfer of a share which is not fully paid up) by or on behalf of the transferee. The transferor shall be deemed to remain the holder of the share until the name of the transferee is entered in the Company’s register of members as the holder of the share. No transfer of any share shall be made: (a) to a minor; or (b) to a bankrupt; or (c) to any person who is, or may be, suffering from mental disorder and either: (i) has been admitted to hospital in pursuance of an application for admission for treatment under the Mental Health Act 1983 (an Act of Parliament) or any similar statute relating to mental health (whether in the United Kingdom, the Isle of Man or elsewhere); or (ii) an order has been made by any court having jurisdiction (whether in the United Kingdom, the Isle of Man or elsewhere) in matters concerning mental disorder for his detention or for the appointment of a receiver, curator bonis or other person to exercise powers with respect to his property or affairs and the Directors shall refuse to register the purported transfer of a share to any such person. The Board may in its absolute discretion and without giving any reason refuse to register any transfer of a certificated share unless: (a) it is in respect of a share which is fully paid up; (b) it is in respect of a share on which the Company has no lien; (c) it is in respect of only one class of shares; (d) it is in favour of a single transferee or not more than four joint transferees; (e) it is duly stamped (if so required); and (f) it is delivered for registration to the registered office of the Company for the time being, or such other place as the Board may from time to time determine, accompanied (except in the case of a transfer where a certificate has not been required to be issued) by the certificate for the shares to which it relates and such other evidence as the Board may reasonably require to prove the title of the transferor and the due execution by him of the transfer or if the transfer is executed by some other person on his behalf, the authority of that person to do so;

202 provided that the Board’s discretion may not be exercised in such a way as to prevent dealings in the shares from taking place on an open and proper basis. The registration of transfers of shares or of any class of shares may be suspended at such times and for such periods (not exceeding thirty days in any year) as the Board may from time to time determine (subject to the Uncertificated Regulations in the case of any shares of a class which is a Participating Security). Notice of closure of the register of members of the Company shall be given in accordance with the requirements of the Acts. The Board shall register a transfer of title to any uncertificated share or the renunciation or transfer of any renounceable right of allotment of a share which is a Participating Security, held in uncertificated form in accordance with the Uncertificated Regulations, except that the Board may refuse (subject to any relevant requirements applicable to the recognised investment exchange(s) to which the shares of the Company are admitted) to register any such transfer or renunciation which is in favour of more than four persons jointly or in any other circumstance permitted by the Uncertificated Regulations. 5.1.5 Dividends Subject to the provisions of the Articles, the Company may by ordinary resolution declare that out of profits available for distribution in accordance with Isle of Man law dividends be paid to members according to their respective rights and interests in the profits of the Company available for distribution. However, no dividend shall exceed the amount recommended by the Board. The Board may declare and pay such interim dividends (including any dividend payable at a fixed rate) as appear to the Board to be justified by the profits of the Company available for distribution in accordance with Isle of Man law and the position of the Company. If at any time the share capital of the Company is divided into different classes, the Board may pay such interim dividends on shares which rank after shares conferring preferential rights with regard to dividend as well as on shares conferring preferential rights unless at the time of payment any preferential dividend is in arrears. Provided that the Board acts in good faith it shall not incur any liability to the holders of shares conferring preferential rights for any loss that they may suffer in consequence of the declaration or by the lawful payment of any interim dividend on any shares ranking after those with preferential rights. If cheques, warrants or orders for dividends or other sums payable in respect of a share sent by the Company to the person entitled thereto by post are returned to the Company undelivered or left uncashed on two consecutive occasions the Company shall not be obliged to send any further dividends or other moneys payable in respect of that share due to that person until he notifies the Company of an address to be used for the purpose. All dividends, interest or other sums payable and unclaimed for 12 months after having become payable may be invested or otherwise made use of by the Board for the benefit of the Company until claimed and the Company shall not be constituted a trustee in respect thereof. All dividends unclaimed for a period of 12 years after having become due for payment shall (if the Board so resolves) be forfeited and shall revert to the Company. 5.1.6 Suspension of rights The Board may at any time serve a notice (‘‘Information Notice’’) upon a member requiring the member to disclose to the Board in writing within such period (being not less than ten days and not more than thirty days) as may be specified in the notice, information relating to any beneficial interest of any third party or any other interest of any kind whatsoever which a third party may have in relation to any or all shares registered in the member’s name. If a member has been issued with an Information Notice and has failed in relation to any shares the subject of the Information Notice (‘‘relevant shares’’) to furnish any information required by such notice within the time period specified therein, then the Board may at any time following fourteen days from the expiry of the date on which the information required to be furnished pursuant to the relevant Information Notice is due to be received by the Board, serve on the relevant holder a notice (in this paragraph called a ‘‘disenfranchisement notice’’) whereupon the following sanctions shall apply: (a) Voting the member shall not with effect from the service of the disenfranchisement notice be entitled in respect of the relevant shares to be present or to vote (either in person or by representative or

203 proxy) at any general meeting of the Company or at any separate meeting of the holders of any class of shares of the Company or on any poll or to exercise any other right conferred by membership in relation to any such meeting or poll; and (b) Dividends and transfers where the relevant shares represent at least 0.25 per cent. in nominal value of their class: (i) any dividend or other money payable in respect of the relevant shares shall be withheld by the Company, which shall not have any obligation to pay interest on it and the member shall not be entitled to elect pursuant to the Articles to receive shares instead of that dividend; and (ii) subject in the case of uncertificated shares to the Uncertificated Regulations, no transfer, other than an approved transfer, of any relevant shares held by the member shall be registered unless the member is not himself in default as regards supplying the information required pursuant to the relevant Information Notice and the member proves to the satisfaction of the Board that no person in default as regards supplying such information is interested in any of the shares which are the subject of the transfer. 5.1.7 Return of capital If the Company is wound up, the surplus assets remaining after payment of all creditors are to be divided among the members in proportion to the capital which at the commencement of the winding up is paid up on the shares held by them respectively and, if such surplus assets are insufficient to repay the whole of the paid up capital, they are to be distributed so that as nearly as may be the losses are borne by the members in proportion to the capital paid up at the commencement of the winding up on the shares held by them respectively, subject to the rights attached to any shares which may be issued on special terms or conditions. If the Company is wound up the liquidator may, with the sanction of a special resolution of the Company and any other sanction required by law, divide among the members in specie the whole or any part of the assets of the Company and may for that purpose value any assets and determine how the division shall be carried out as between the members or different classes of members. Any such division may be otherwise than in accordance with the existing rights of the members but if any division is resolved otherwise than in accordance with such rights the members shall have the same right of dissent and consequential rights as if such resolution were a special resolution passed pursuant to Section 222 of the Isle of Man Companies Act 1931. The liquidator may with the like sanction vest the whole or any part of the whole of the assets in trustees on such trusts for the benefit of the members as he with the like sanction shall determine but no member shall be compelled to accept any assets on which there is a liability. A special resolution sanctioning a transfer or sale to another company duly passed pursuant to Section 222 of the Isle of Man Companies Act 1931 may in the like manner authorise the distribution of any shares or other consideration receivable by the liquidator among the members otherwise than in accordance with their existing rights and any such determination shall be binding on all the members, subject to the right of dissent and consequential rights conferred by the said section. 5.1.8 Pre-emption rights Except in relation to the grant and exercise of Options pursuant to the Share Option Scheme and unless the Company shall by special resolution otherwise direct, unissued shares in the capital of the Company shall only be allotted for cash in accordance with the following provisions: (a) all shares to be allotted (the ‘‘offer shares’’) shall first be offered to the members of the Company in proportion to their existing holdings of shares (the ‘‘initial offer’’); (b) the initial offer shall be made by written notice (the ‘‘offer notice’’) from the Directors specifying the number and price of the offer shares and shall invite each member to state in writing within a period, not being less than 28 days, whether they are willing to accept any offer shares and, if so, the maximum number of offer shares they are willing to take; (c) at the expiration of the time specified for acceptance in the offer notice the Directors shall allocate the offer shares to or amongst the members who shall have notified to the Directors their willingness to take any of the offer shares but so that no member shall be obliged to take more than the maximum number of shares notified by him under paragraph 5.1.8 (b);

204 (d) if any offer shares remain unallocated after the initial offer the Directors shall make a further offer (the ‘‘further offer’’) in writing (the ‘‘further offer notice’’) on the same terms as the initial offer to members who shall have expressed their willingness to purchase the offer shares and, if there is more than one member to whom this provision applies, then the further offer shall be pro rata to their existing holdings of shares; (e) at the expiration of the time specified for acceptance in the further offer notice the Directors shall allocate the offer shares to or amongst the members who shall have notified to the Directors their willingness to take any of the offer shares but so that no member shall be obliged to take more than the maximum number of shares notified by him under paragraph 5.13.(d); (f) if any offer shares remain unallocated after the further offer, the Directors shall be entitled to allot, grant options over or otherwise dispose of those shares to such persons on such terms and in such manner as they think fit save that those shares shall not be disposed of on terms which are more favourable to their subscribers than the terms on which they were offered to the members. The above provisions do not apply to the allotment of any shares for a consideration other than cash and, accordingly, the Directors may allot or otherwise dispose of any unissued shares in the capital of the Company for a consideration other than for cash to such persons at such times and generally on such terms as they may think fit. 5.1.9 Borrowing powers Subject to the other provisions of the Articles and to the Acts, the Directors may exercise all the powers of the Company to borrow money, to guarantee, to indemnify and to mortgage or charge its undertaking, property, assets (present and future) and uncalled capital or any part or parts thereof and to issue debentures and other securities, whether outright or as collateral security for any debt, liability or obligation of the Company or of any third party. 5.1.10 Directors The Articles provide that, unless and until otherwise determined by the Company by ordinary resolution, the number of Directors (other than any alternate Directors) shall be not less than two and shall not be greater than twelve. Subject to the provisions of the Articles, the Company may by ordinary resolution appoint a person who is willing to act to be a Director, either to fill a vacancy, or as an addition to the existing Board, and may also determine the rotation in which any additional Directors are to retire, but the total number of Directors shall not exceed any maximum number fixed in accordance with the Articles. No person shall be disqualified from being appointed or re-appointed a Director, and no Director shall be required to vacate that office, by reason only of the fact that he has attained the age of 70 years or any other age nor shall it be necessary by reason of his age to give special notice of any resolution. At each annual general meeting, one third of the Directors shall retire from office. A retiring Director shall be eligible for re-election at such annual general meeting. A Director shall not be required to hold any shares in the capital of the Company by way of qualification. The Directors (other than alternate Directors) shall be entitled to receive by way of fees for their services as Directors such sum as the Board may from time to time determine (not exceeding US$500,000 per annum or such other sum as the Company in general meeting shall from time to time determine). Such sum (unless otherwise directed by the resolution of the Company by which it is voted) shall be divided among the Directors in such proportions and in such manner as the Board may determine or, in default of such determination, equally (except that in such event any Director holding office for less than the whole of the relevant period in respect of which the fees are paid shall only rank in such division in proportion to the time during such period for which he holds office). Any fees payable pursuant to this provision shall be distinct from any salary, remuneration or other amounts payable to a Director pursuant to any other provisions of the Articles and shall accrue from day to day. The salary or remuneration of any Director appointed to hold any employment or executive office in accordance with the provisions of the Articles may be either a fixed sum of money or may

205 altogether or in part be governed by business done or profits made or otherwise determined by the Board and may be in addition to or in lieu of any fee payable to him for his services as Director pursuant to the Articles. Each Director shall be entitled to be repaid all reasonable traveling, hotel and other expenses properly incurred by him in or about the performance of his duties as Director, including any expenses incurred in attending meetings of the Board or any committee of the Board or general meetings or separate meetings of the holders of any class of shares or of debentures of the Company. 5.1.11 Directors’ interests and indemnity A Director who to his knowledge is in any way (directly or indirectly) interested in any contract arrangement, transaction or proposal with the Company shall declare the nature of his interest at the meeting of the Board at which the question of entering into the contract, arrangement, transaction or proposal is first considered if he knows his interest then exists or, in any other case, at the first meeting of the Board after he knows that he is or has become so interested. Except as provided below, a Director shall not vote on or be counted in the quorum in relation to any resolution of the Board or of a committee of the Board concerning any contract, arrangement, transaction or any proposal whatsoever to which the Company is or is to be a party and in which he has (directly or indirectly) an interest which is material (other than by virtue of his interests in shares or debentures or other securities of, or otherwise in or through the Company) or a duty which conflicts with the interests of the Company unless his duty or interest arises only because the resolution relates to one of the matters set out in the following sub-paragraphs in which case he shall be entitled to vote and be counted in the quorum: (a) the giving to him of any guarantee, security or indemnity in respect of money lent or obligations incurred by him at the request of or for the benefit of the Company or any of its subsidiaries; (b) the giving to a third party of any guarantee, security or indemnity in respect of a debt or obligation of the Company or any of its subsidiaries for which he himself has assumed responsibility in whole or in part either alone or jointly with others, under a guarantee or indemnity or by the giving of security; (c) where the Company or any of its subsidiaries is offering securities in which offer the Director is or may be entitled to participate as a holder of securities or in the underwriting or sub-underwriting of which the Director is to participate; (d) relating to another company in which he and any persons connected with him do not to his knowledge hold an interest in shares representing one per cent or more of either any class of the equity share capital, or the voting rights, in such company; (e) relating to an arrangement for the benefit of the employees of the Company or any of its subsidiaries which does not award him any privilege or benefit not generally awarded to the employees to whom such arrangement relates; or (f) concerning insurance which the Company proposes to maintain or purchase for the benefit of Directors or for the benefit of persons including Directors. An interest of a person who is, for any purpose of the Acts (excluding any such modification thereof not in force when the Articles became binding on the Company), connected with a Director shall be treated as an interest of the Director and, in relation to an alternate Director, an interest of his appointor shall be treated as an interest of the alternate Director without prejudice to any interest which the alternate Director otherwise has. A Director shall not vote or be counted in the quorum on any resolution of the Board or committee of the Board concerning his own appointment (including fixing or varying the terms of his appointment or its termination) as the holder of any office or place of profit with the Company or any company in which the Company is interested. Where proposals are under consideration concerning the appointment (including fixing or varying the terms of appointment or termination) of two or more Directors to offices or places of profit with the Company or any company in which the Company is interested, such proposals may be divided and a separate resolution considered in relation to each Director. In such case each of the Directors concerned (if not otherwise debarred from voting under the Articles) shall be entitled to vote (and be counted in the quorum) in respect of each resolution except that concerning his own appointment.

206 Subject to the Acts, but without prejudice to any indemnity to which he may otherwise be entitled, every Director, alternate Director, secretary or other officer of the Company (other than on auditor) shall be entitled to be indemnified out of the assets of the Company against all costs, charges, losses, damages and liabilities incurred by him in the actual or purported execution of his duties. 5.1.12 General Meetings Subject to the provisions of the Acts, annual general meetings shall be held at such time and place as the Board may determine but in any event no more than fifteen months after the previous annual general meeting. All general meetings other than annual general meetings, shall be called extraordinary general meetings. The Board may convene an extraordinary general meeting whenever it thinks fit. At any meeting convened on such requisition (or any meeting requisitioned pursuant to section 113 of the Companies Act 1931) no business shall be transacted except that stated by the requisition or proposed by the Board. If there are not within the Isle of Man sufficient members of the Board to convene a general meeting, any Director or any member of the Company may call a general meeting. An annual general meeting and an extraordinary general meeting convened for the passing of a special resolution or a resolution appointing a person as a Director or a resolution of which special notice has been given to the Company shall be convened by not less than 21 clear days’ notice in writing. Other extraordinary general meetings shall be convened by not less than 14 clear days’ notice in writing. No business shall be transacted at any general meeting unless a quorum is present when the meeting proceeds to business but the absence of a quorum shall not preclude the choice or appointment of a Chairman, which shall not be treated as part of the business of the meeting. Subject to the provisions of the Articles, two persons entitled to attend and to vote on the business to be transacted, each being a member present in person or a proxy for a member or a duly authorised representative of a corporation which is a member, shall be a quorum). If, within 15 minutes (or such longer interval not exceeding one hour as the Chairman in his absolute discretion thinks fit) from the time appointed for the holding of a general meeting, a quorum is not present or if, during a meeting, such a quorum ceases to be present, the meeting, if convened on the requisition of members, shall be dissolved. In any other case, the meeting shall stand adjourned to the same day in the next week at the same time and place, or to such other day and at such time and place as the Chairman (or, in default, the Board) may determine, being not less than 14 nor more than 28 days thereafter. If, at such adjourned meeting, a quorum is not present within 15 minutes from the time appointed for holding the meeting, one member present in person or by proxy or (being a corporation) by a duly authorised representative shall be a quorum. If no such quorum is present or if, during the adjourned meeting, a quorum ceases to be present, the adjourned meeting shall be dissolved. The Company shall give at least seven clear days’ notice of any meeting adjourned through lack of quorum (where such meeting is adjourned to a day being not less than 14 nor more than 28 days thereafter). 5.1.13 Compulsory Transfer If it shall come to the notice of the Board that any shares: (a) are or may be owned or held directly or beneficially by any person in breach of any law or requirement of any country or by virtue of which such person is not qualified to own those shares and, in the sole and conclusive determination of the Board, such ownership or holding or continued ownership or holding of those shares (whether on its own or in conjunction with any other circumstance appearing to the Board to be relevant) would in the reasonable opinion of the Board, cause a pecuniary or tax disadvantage to the Company or any other holder of shares or other securities of the Company which it or they might not otherwise have suffered or incurred; or (b) are or may be owned or held directly or beneficially by any person that is an employee benefit plan subject to Title I of the US Employee Retirement Income Security Act of 1974, as amended (‘‘ERISA’’), or other plan subject to Section 4975 of the US Internal Revenue Code of 1986, as amended, and in the opinion of the Board the assets of the Company may be considered ‘‘plan assets’’ within the meaning of Section 3(42) of ERISA; or

207 (c) are or may be owned or held directly or beneficially by any person to whom a transfer of shares or whose ownership or holding of any shares might in the opinion of the Board require registration of the Company as an investment company under the US Investment Company Act of 1940, as amended; or (d) are or may be owned or held directly or beneficially by any ‘‘United States person’’ (as defined in Section 957(c) of the US Internal Revenue Code of 1986, as amended) and such person’s shareholding amounts to ten per cent. or more of the shares, unless otherwise approved by the Board (collectively, a ‘‘Prohibited Person’’), the Board may serve written notice (hereinafter called a ‘‘Transfer Notice’’) upon the person (or any one of such persons whose shares are registered in joint names) appearing in the register as the holder (the ‘‘Vendor’’) of any of the shares concerned (the ‘‘Relevant Shares’’) requiring the Vendor within ten days (or such extended time as in all the circumstances the Board consider reasonable) to transfer (and/or procure the disposal of interests in) the Relevant Shares to another person who, in the sole and conclusive determination of the Board, would not fall within paragraph (a), (b), (c) or (d) above (such a person being hereinafter called an ‘‘Eligible Transferee’’). On and after the date of such Transfer Notice, and until registration of a transfer of the Relevant Shares to which it relates pursuant to the provisions referred to in this paragraph or the paragraph below, the rights and privileges attaching to the Relevant Shares will be suspended and not capable of exercise. If within ten days after the giving of a Transfer Notice (or such extended time as in the circumstances the Board consider reasonable) the Transfer Notice has not been complied with to the satisfaction of the Board, the Company may sell the Relevant Shares on behalf of the holder thereof by instructing a London Stock Exchange member firm to sell them at the best price reasonably obtainable at the time of sale to any one or more Eligible Transferees. To give effect to a sale the Board may authorise in writing any officer or employee or the secretary of the Company to transfer the Relevant Shares on behalf of the holder thereof (or any person who is automatically entitled to the shares by transmission or by law) or to cause the transfer of the Relevant Shares to the purchaser and in relation to an uncertificated share may require the Operator to convert the share into certificated form and an instrument of transfer executed by that person shall be as effective as if it had been executed by the holder of, or the person entitled by transmission to, the Relevant Shares. The purchaser is not bound to see to the application of the purchase money and the title of the transferee is not affected by any irregularity in or invalidity of the proceedings connected to the sale. The net proceeds of the sale of the Relevant Shares, after payment of the Company’s costs of the sale, shall be paid by the Company to the Vendor or, if reasonable enquiries have failed to establish the location of the Vendor, into a trust account at a bank designated by the Company, the associated costs of which shall be borne by such trust account. The Company may register or cause the registration of the transferee as holder of the Relevant Shares and thereupon the transferee shall become absolutely entitled thereto. A person who becomes aware that he falls, or is likely to fall, within any of sub-paragraphs (a), (b), (c) or (d) above shall forthwith, unless he has already received a Transfer Notice pursuant to the above provisions, either transfer the shares to one or more Eligible Transferees or give a request in writing to the Board for the issue of a Transfer Notice in accordance with the above provisions. Every such request shall, in the case of certificated shares, be accompanied by the certificate(s) for the shares to which it relates. Subject to the provisions of the Articles, the Board shall, unless any Director has reason to believe otherwise, be entitled to assume without enquiry that none of the shares are held in such a way as to entitle the Board to serve a Transfer Notice in respect thereof. The Board may, however, at any time and from time to time call upon any holder (or any one of joint holders or a person who is automatically entitled to the shares by transmission or by law) of shares by notice in writing to provide such information and evidence as they require upon any matter connected with or in relation to such holders of shares. In the event of such information and evidence not being so provided within such reasonable period (not being less than ten clear days after service of the notice requiring the same) as may be specified by the Board in the said notice, the Board may, in its absolute discretion, treat any share held by such a holder or joint holders or person who is automatically entitled to the shares by transmission or by law as being held in such a way as to entitle them to serve a Transfer Notice in respect thereof.

208 The Board will not be required to give any reasons for any decision, determination or declaration taken or made in accordance with these provisions. The exercise of the powers conferred by the provisions referred to above may not be questioned or invalidated in any case on the grounds that there was insufficient evidence of direct or indirect beneficial ownership or holding of shares by any person or that the true direct or beneficial owner or holder of any shares was otherwise than as appeared to the Board at the relevant date provided that the said powers have been exercised in good faith.

5.1.14 Disclosure of shareholdings

Every person who is to his knowledge interested in the voting rights of three per cent. or more of the issued shares of any relevant class of shares in the capital of the Company, shall without delay, give to the Company notice in writing of the following information:

(a) the amount of shares of the relevant class in which he was to his knowledge directly or indirectly interested immediately after the obligation arose and the percentage of voting rights in the Company held through those shares (and/or any other direct or indirect holding of qualifying financial instruments in such shares); and

(b) the following information: (i) the identity and address of each registered holder of those shares (and person(s) entitled to exercise voting rights on behalf of such registered holder, if applicable) and the amount of shares then held by each such holder; (ii) the chain of controlled undertakings through which voting rights are effectively held, if applicable; (iii) the date on which the threshold was reached or crossed; and (iv) in respect of any notification of voting rights arising from the holding of financial instruments by that shareholder, the following shall be required:

(A) the resulting situation in terms of voting rights;

(B) if applicable, the chain of controlled undertakings through which the financial instruments are effectively held;

(D) for financial instruments with an exercise period, an indication of the date or time period where shares will or can be acquired, if applicable;

(E) the date of maturity or expiration of the financial instrument;

(F) the identity of the holder; and

(G) the name of the underlying issuer of such financial instrument.

5.2 Squeeze out provisions

Isle of Man companies legislation contains provisions for the squeeze out of dissenting shareholders in a take-over situation, based on similar concepts to those existing under English law. The relevant provisions (the ‘‘Squeeze-Out Provisions’’) are contained in section 154 of the Isle of Man Companies Act 1931 (the ‘‘1931 Act’’).

The Squeeze-Out Provisions set out in the 1931 Act provide, essentially, that, where a scheme or contract involving the transfer of shares or any class of shares in a company (the ‘‘transferor company’’) to another company (not being restricted to an Isle of Man company) (the ‘‘transferee company’’) has within four months after the making of the offer by the transferee company been approved by the holders of not less than 90 per cent. in value of the shares affected, the transferee company may, at any time within two months after the expiry of the four-month period mentioned, give notice to any dissenting shareholder that it desires to acquire his shares. Unless, upon an application by a dissenting shareholder within one month from the date on which the notice was given the court orders otherwise, the transferee company shall be entitled and bound to acquire those shares. The Squeeze-Out Provisions also contain details on the procedure that has to be adopted to ensure that the shares which the transferee company is bound to acquire are transferred to it and that the consideration that it is bound to pay reaches the shareholders concerned.

209 6. SUMMARY OF THE COMPANY’S SHARE OPTION SCHEME 6.1 General 6.1.1 The Company has adopted the Share Option Scheme which allows it to grant options to subscribe for Ordinary Shares in the Company (at the discretion of the Board or a duly authorised committee thereof (ie the remuneration committee)) to selected employees or directors of the Group. The principal provisions of the Share Option Scheme are summarised below. 6.1.2 The approval of HM Revenue & Customs has not been obtained in respect of the Share Option Scheme. 6.2 Grant of Options 6.2.1 Options may normally only be granted within 42 days after announcement of the Group’s preliminary or interim results or to an individual within 14 days of that individual becoming an employee or director of the Group. However, Options may be granted outside this period if the Board or the remuneration committee consider that the circumstances are exceptional. 6.2.2 Options must be granted at a subscription price per Ordinary Share which is at least the greater of: 6.2.2.1 the average middle market quotation of an Ordinary Share over the five dealing days immediately preceding the date on which the Option is granted (where the Ordinary Shares are listed on the Official List); and 6.2.2.2 US$0.01 (being the nominal value of an Ordinary Share). 6.2.3 No consideration is payable for the grant of an Option. Options are not transferable or assignable (other than to a personal representative in the event that an Option holder dies). 6.2.4 Options may be granted at the discretion of the Board or the remuneration committee on such terms as the Board shall determine. 6.2.5 Options granted or the benefit thereof shall not (except as may be required by taxation law) form part of the emoluments of the participators or count as wages or remuneration for pension and other purposes. 6.3 Number of Ordinary Shares under Share Option Scheme 6.3.1 The number of Ordinary Shares which may be utilised under all employee share schemes established by the Company shall not exceed 10 per cent. of the issued ordinary share capital of the Company within any ten year period preceding the date of the grant. This does not include Options which have lapsed or been surrendered. 6.4 Exercise of Options and Vesting 6.4.1 The exercise of an Option may be made subject to the achievement of specific performance targets or other conditions to be determined by the Board or the remuneration committee. In the future it is intended to grant Options which generally vest in three equal instalments over a three year period but (due to the nature of the Group’s business) are not subject to any other performance conditions. In certain circumstances, the Board or the remuneration committee has discretion to allow an Option to vest earlier (for example on a takeover of the Company). In the event of a take-over or reconstruction of the Company any performance target must be satisfied (this will be on a pro-rata basis where an Option vests earlier than the date set out in the option certificate). 6.4.2 An Option will lapse on the tenth anniversary of the date of grant of the Option. An Option will also lapse if the Option holder leaves employment with the Group for any reason, subject to the discretion of the Board or the remuneration committee to permit the Option holder to exercise the Option within a restricted period thereafter. In exercising its discretion the Board will take into account the circumstances in which the Option holder left employment with the Group. 6.4.3 If an Option holder dies his personal representative may exercise his Option (to the extent it is capable of being exercised) within a restricted period thereafter. Such period shall not be greater than twelve months from the date of death.

210 6.4.4 In the event of a general offer to acquire the whole of the issued share capital of the Company as a result of which the offeror obtains control of the Company, an Option holder may, with the consent of the acquiring company, release each subsisting and unexercised option for a new right which is equivalent to his Option but relates to shares in a different company (generally, the offeror). If another company obtains control of the Company then Options which are not exercised within a restricted period thereafter will lapse. 6.5 Amendment 6.5.1 The number and/or class of shares and the subscription price of shares subject to an Option may be varied by the Board or the remuneration committee in the event of a reorganisation of capital (such as a capitalisation or rights issue) subject to an opinion of the auditors of the Company that the variations are fair and reasonable. 6.5.2 The Share Option Scheme will be administered by the Board or the remuneration committee. The Board has the power to amend the Share Option Scheme, but (a) no amendment may be made which would materially affect the existing rights of an Option holder unless it has been approved by a majority of Option holders and (b) no amendment may be made to the matters referred to in this summary which is to the advantage of existing or future Option holders (other than minor amendments for general administrative, fiscal or regulatory benefit) except with the consent of the Company in general meeting. 6.6 Termination and Term 6.6.1 The Board or the remuneration committee may terminate the Share Option Scheme at any time with the effect that no further Options may thereafter be granted although in all other respects the Share Option Scheme will remain in force. 6.6.2 No Options may be granted under the Share Option Scheme after the tenth anniversary of its adoption. 6.7 In addition to the Options held by the Directors and Senior Managers set out in paragraph 7.5 the following Options held by employees of the Group are outstanding under the Share Option Scheme: Number of Number of Ordinary Shares Exercise Price Ordinary Shares under Option per Ordinary Date of Grant under Option which have Vested Expiry Date Share (pence) 7 June 2005 85,000 56,667 6 June 2015 144 1 November 2005 85,000 56,667 31 October 2015 239 21 March 2006 10,000 3,333 20 March 2016 302 13 April 2006 5,000 1,667 12 April 2016 308 20 April 2006 10,000 3,333 19 April 2016 338 10 May 2006 5,000 1,667 9 May 2016 367 24 November 2006 10,000 3,333 23 November 2016 266 2 February 2007 415,000 138,333 1 February 2017 308 7. DIRECTORS AND SENIOR MANAGEMENT 7.1 Directors and Senior Managers of the Company The Directors are: Paul Mortimer (Non-Executive Chairman) Sastry Karra (Chief Executive) Yogeshwar Sharma (Chief Operating Officer) Dinesh Dattani (Finance Director) Pradip Shah (Non-Executive Director) Carol Bell (Non-Executive Director) all of 15-19 Athol Street, Douglas, Isle of Man, IM1 1LB. The Senior Managers of the Group are: Ramasamy Jeevanandam (Chief Financial Officer and director, Hardy Exploration & Production (India) Inc), Ravi Venkateswaran (Country Manager, Hardy Oil Nigeria Limited).

211 7.2 None of the Directors or Senior Managers has any business interests nor performs any activities outside the Group which are significant with respect to the Group. No Director or Senior Manager has any conflict of interest between his duties to the Company and any private interests or other duties.

7.3 Interests in the Ordinary Shares

7.4 As at 14 February 2008 (being the latest practicable date prior to the publication of this document), the voting rights held, directly or indirectly, by the Directors and the Senior Managers in respect of the Ordinary Shares, was as follows: Percentage of voting Director/Senior Number of rights in respect of Manager Ordinary Shares Ordinary Shares (%) Paul Mortimer 870,051 1.40 Sastry Karra 8,455,200(1) 13.58 Yogeshwar Sharma 4,229,400(2) 6.79 Dinesh Dattani Nil Nil Pradip Shah 664,435 1.07 Carol Bell Nil Nil Ramasamy Jeevanandam 600,000(3) 0.96 Ravi Venkateswaran 195,000 0.31

(1) Of this amount, 6,000,000 Ordinary Shares are registered in the name of NY Nominees Limited and 2,455,200 Ordinary Shares in the name of HSBC Global Custody Nominee U.K. Limited.

(2) Registered in the name of Bank of New York Nominees Limited.

(3) Registered in the name of Pershing Keen Nominees Limited. 7.5 As at 14 February 2008 (being the latest practicable date prior to the publication of this document) the Directors and the Senior Managers hold the following Options granted pursuant to the Share Option Scheme (the terms of which are summarised in paragraph 6 of this part 6):

Number of Exercise Ordinary Shares Price per Number of under Option Ordinary Date of Ordinary Shares which have Share Director Grant under Option vested Expiry Date (pence) Paul Mortimer 7 June 2005 260,233 173,489 6 June 2015 144 Yogeshwar 7 June 2005 780,700 520,467 6 June 2015 144 Sharma 2 July 2007 300,000 Nil 1 July 2017 431 Sastry Karra 7 June 2005 780,700 520,467 6 June 2015 144 2 July 2007 400,000 Nil 1 July 2017 431 Dinesh Dattani 2 July 2007 400,000 Nil 1 July 2017 431 Pradip Shah 7 June 2005 260,233 173,489 6 June 2015 144 Carol Bell 22 December 2005 260,233 173,489 21 December 2015 276 Ramasamy 7 June 2005 100,000 66,667 6 June 2015 144 Jeevanandam 2 February 2007 150,000 50,000 1 February 2017 308 Ravi 7 June 2005 25,000 16,667 6 June 2015 144 Venkateswaran 2 February 2007 10,000 3,333 1 February 2017 308

7.6 Save as disclosed in this paragraph 7 neither the Directors nor the Senior Managers have any interest in the share capital of the Company.

212 7.7 Directorships and partnerships

In addition to their directorships in the Company, the Directors and Senior Managers are currently or have been directors and/or partners in the following companies and partnerships at any time in the five years preceding the date of this document: Name Current Directorships Previous Directorships

Sastry Karra Care Technologies India (P) Ltd. Heramec Ltd. Deccan Logistics (P) Ltd. Jehan Energy (U.K.) Limited Hardy Exploration and Production (India) Inc. Hardy Oil (Africa) Limited Hardy Oil Nigeria Limited Notion Music Limited One Service Internal Inc. Riverside Limited Notion Music Inc. Yogeshwar Sharma Hardy Exploration and Production Eptech International Limited (India) Inc. Heramec Ltd Hardy Oil (Africa) Limited Jehan Energy (U.K.) Limited Hardy Oil Nigeria Limited Pradip Shah AMP IndAsia Fund Advisors Ltd Bharatiya Reserve bank Note Mudran Asset Reconstruction Company Limited (India) Ltd EuroAsia Investment & Financial BASF India Limited Advisors Limited Godrej & Boyce Mfg. Limited Gujarat Positra Port Infrastructure Grindwell Norton Limited Limited IndAsia Fund Advisors Private Limited Gujarat Informatics Limited Kansai Nerolac Paints Limited Gokaldas Exports Limited Mukund Limited Indocam Himalayan Fund, NV Panasonic Battery India Co. Limited NDC Telecommunications India Pvt. Ltd Pfizer Limited Prudential ICICI Asset Management Patni Computer Systems Limited Company Limited Shah Foods Limited Shipping Corporation of India Limited Sonata Software Limited Tata Infomedia Limited Supra Advisors (BVI) Limited Bombay Stock Exchange Limited Wartsila India Limited TAIB Bank, E.C. Xius Technology Ltd Wockhardt Hospitals Limited Zip Global Networking Limited Vakrangee Softwares Limited

213 Name Current Directorships Previous Directorships

Paul Mortimer Alliance Energy, Inc. Hoegh Capital Partners (PE) Limited Arts Alliance Digital Ventures III, Limited Hoegh Capital Partners (ARP) Arts Alliance Labs, Inc. Fund Limited Arts Alliance Screens Holdings Limited Hoegh Capital Partners (FI) Fund African Highlands Limited Limited Digital Ventures II Limited Stamford Bridge One Limited Digital Ventures Holdings Limited Gadus International Limited Gadus America, Inc. Goran Enterprises Limited Gadus (PE) II, Inc. Argon Investments Limited Gemini Oil & Gas Limited Pomor Holdings Limited HCP (PE) I, Inc. Mortimer Scott Associates, Inc. HCP (PE) II, Inc. HCP (PE) III, Inc. HCP (PE) IV, Inc. HCP (PE) V, Inc. Hoegh Capital Partners, Inc. Hoegh Capital Partners Advisors (BVI), Inc. Hoegh Capital Partners General Equity Fund Limited Hoegh Capital Partners PE (US) Limited Baobab Limited Rift Valley Holdings Limited Streamcourse Limited Gemini Oil and Gas Management Limited Dinesh Dattani Petroleo La Plata Inc. Coyotenet Communications Group Ltd. Double D Ventures Inc. Globex Resources Ltd. Sonoma Resources Ltd. Legacy Petroleum International Inc. Spherical Capital Inc. Stone Castle Exploration Ltd. WaveForm Acquisition Corp. WaveForm Energy Ltd. Carol Bell Revus Energy ASA Osprey Oil & Gas Limited Ramasamy Hardy Exploration & Prodution None Jeevanandam (India) Inc. Ravi None None Venkateswaran

7.8 Paul Mortimer was chairman of Cimage Corporation (a Delaware corporation) which appointed an insolvency trustee on 20 June 1995 to dispose of assets and settle creditors claims of approximately US$12 million.

7.9 Receiverships, liquidations and administrations

7.9.1 As at the date of this document, save as set out above, no Director or Senior Manager has for at least the previous five years:

7.9.2 received any convictions in relation to fraudulent offences;

7.9.3 has been a director, partner or member of the administrative, management or supervisory bodies of any company at the time or 12 months preceding any bankruptcy, administration, receivership, compulsory liquidation, or creditors’ voluntary liquidation;

7.9.4 has been bankrupt or the subject of an individual voluntary arrangement, or has had a receiver appointed to any of his assets;

214 7.9.5 has been subject to any official public incrimination or sanction of him by any statutory or regulatory authority (including designated professional bodies), nor has ever been disqualified by a court from acting as a director of a company or from acting as a member of the administrative, management or supervisory bodies of an issuer or from acting in the management or conduct of the affairs of any issuer.

7.10 Save for the directorships and partnerships disclosed in paragraph 7.7 above none of the Directors or Senior Managers have any potential conflicts of interests between their duties to the Company and their private interests or other duties.

8. DIRECTORS’ SERVICE AGREEMENTS AND LETTERS OF APPOINTMENT

8.1 Sastry Karra entered into parallel service agreements with the Company and HEPI (with the payment of salary and other individual terms being governed by the agreement with HEPI) dated 2 June 2005. His appointment is subject to termination upon 6 months’ notice by either party. The agreement provides for an annual salary of US$180,000, membership of a private medical scheme, permanent health insurance, life assurance cover and pension contributions of 4 per cent. of his salary. Mr Karra’s salary was increased to £200,000 per annum, effective 1 July 2007.

8.2 Yogeshwar Sharma entered into parallel services agreements with the Company and HEPI (with the payment of salary and other individual terms being governed by the agreement with HEPI) dated 2 June 2005. His appointment is subject to termination upon 6 months’ notice by either party. The agreement provides for an annual salary of US$180,000, the use of a company car, membership of a private medical scheme, permanent health insurance, life assurance cover and pension contributions of 4 per cent. of his salary. Mr Sharma’s salary was increased to £200,000 per annum, effective 1 July 2007.

8.3 Dinesh Dattani entered into a service agreement with the Company with an effective date of 1 July 2007, subject to termination upon 12 months notice by the Company and 90 days by Mr Dattani. The agreement provides for an annual salary of £191,250, membership of a private medical scheme and life assurance cover.

8.4 The services of Paul Mortimer, Pradip Shah and Carol Bell as non-executive Directors are provided under the terms of agreements with the Company and each non-executive director dated 2 June 2005 (with respect to Messrs Mortimer and Shah) and 16 December 2005 with respect to Dr Bell). The appointments are subject to termination upon at least 3 months’ notice and an initial fee of US$30,000 per annum. Upon Admission, the annual fees for the non- executive directors will increase and it has been agreed that Mr Mortimer shall be paid £48,000 per annum and Mr Shah and Dr Bell shall each be paid £36,000 per annum.

8.5 Under the terms of Messrs Karra, Sharma and Dattani’s service agreements the Company may in lieu of notice terminate the executive’s employment with immediate effect but in such instance must pay the executive a lump sum equal to basic salary at the rate prevailing at the date of termination for a period of 12 months, and bonus to the extent earned and awarded by the Company at the date of termination in lieu of the notice period. In addition, in the event of a change of control the Company may be entitled to terminate the executive’s employment on payment of 12 months’ salary together with all benefits and bonuses.

8.6 Save as detailed above, there are no other service contracts between any of the Directors and the Company providing for benefit upon termination of employment.

8.7 Under the Articles, one-third of the Directors, or if their number is not a multiple of 3, the number nearest to but not exceeding one third are obliged to retire by rotation at each annual general meeting.

215 9. REMUNERATION AND BENEFITS 9.1 The aggregate emoluments of each of the Directors and the Senior Managers (including benefits in kind) for the financial accounting period ending 31 December 2006 were as follows: Name Salary/Fee Benefits in Kind Total Carol Bell US$30,000 — US$30,000 Sastry Karra US$180,000 US$154,450 US$334,450 Paul Mortimer US$30,000 — US$30,000 Pradip Shah US$30,000 — US$30,000 Yogeshwar Sharma US$201,436 US$33,246 US$234,682 Ramasamy Jeevanandam US$106,157 US$16,882 US$123,039 Ravi Venkateswaran US$229,000 — US$229,000

9.2 Dinesh Dattani was not an employee of the Company in the financial year ending 31 December 2006. Mr Dattani was appointed to the Board on 1 July 2007. 9.3 The aggregate amount accrued in relation to pension, retirement and other similar benefits for the Directors and the Senior Managers in the financial accounting period ending 31 December 2006 was US$nil.

10. SIGNIFICANT SHAREHOLDERS 10.1 As at 14 February 2008 (being the latest practicable date prior to publication of this document), in addition to the holdings of the Directors in paragraph 7.4 above, the Company is aware of the following additional persons who, directly or indirectly, has an interest in three per cent., or more of the Company’s issued Ordinary Shares or voting rights: Percentage of Number of Voting Rights in Ordinary Shares respect of Ordinary Shares (%)

Lloyds TSB Group plc 4,930,002 7.92 Limpopo Investments Limited 4,874,162 7.83 Grahame Whately 3,430,361 5.51 Aegon Asset Management 2,181,343 3.50 Universities Superannuation 2,012,608 3.23 Scheme Limited Interstellar Enterprise Limited 1,876,105 3.01 Pomor Holding Limited 1,800,583 2.89 Vind Sweden AB 1,755,583 2.82

10.2 None of the Company’s major holders of Ordinary Shares listed in paragraph 10.1 or paragraph 7.4 above have voting rights different from other holders of Ordinary Shares. 10.3 As far as the Company is aware, as at 14 February 2008 (being the last practicable date prior to the publication of this document) there are no arrangements the operation of which may at a later date result in a change of control of the Company save for the arrangements described in this document. 10.4 The Company is not aware of any person who either as at the date of this document or immediately following Admission exercises, or could exercise, directly or indirectly, control over the Company.

11. TAXATION The information below, which is of a general nature only and which relates only to UK and Isle of Man taxation, is applicable to the Company and to persons who are resident or ordinarily resident in the UK (except where indicated) and who hold Ordinary Shares as an investment. It is based

216 on existing law and practice and is subject to subsequent changes thereto. Anyone who is in any doubt as to his position should consult his professional adviser without delay. 11.1 Isle of Man In principle, taxes which are charged in the Isle of Man by the Isle of Man Government include: (i) indirect taxes in the form of value added tax, customs and excise duties and vehicle licence duty; and (ii) direct tax in the form of income tax, or Distributable Profits Charge (defined below) which is chargeable upon income arising or accruing from sources in the Isle of Man or income arising or accruing from sources outside the Isle of Man that belong to persons residing in the Isle of Man. No capital gains tax is charged in the Isle of Man. The Company The Company is resident for taxation purposes in the Isle of Man by virtue of incorporation. With effect from 6 April 2006 the Isle of Man introduced a zero rate of tax for all companies except those which derive their income from banking business or land and property in the Isle of Man or who elect to pay income tax at a rate of 10 per cent., (‘‘the zero/10 regime’’). The Company falls into none of the 10 per cent. categories at present and therefore is potentially able to qualify for the zero rate regime. Alongside the zero/10 regime the Isle of Man introduced the Distributable Profits Charge (‘‘DPC’’) which is a tax charge levied on companies that do not qualify as ‘‘Distributing Companies’’. Distributing Companies pay no Isle of Man income taxes or DPC. To qualify as a Distributing Company, a company must be one that: ț distributes the required amount of its profits, which is 55 per cent. for a trading company and 100 per cent. for an investment company, or ț already pays Isle of Man income tax at 10 per cent. on all of its profits, or ț elects to pay Isle of Man income tax at 10 per cent., or ț holds a banking licence, or ț the members cannot benefit from distributions, or ț is exempt from income tax on its profits (e.g. a registered charity), or ț is listed on a recognised stock exchange. The Official List of the London Stock Exchange and AIM qualify as recognised stock exchanges for the purpose of the Isle of Man DPC regulations. Therefore unless the Company’s activities involve deriving income from banking business or land and property in the Isle of Man or it elects to pay Isle of Man income tax at 10% then if it continues to maintain its listing on AIM and when it achieves a full listing on the LSE it will be classed as a Distributing Company for DPC purposes and the zero rate of income tax will apply, so that there will be no Isle of Man tax charge on the Company’s income or profits. Recently the Isle of Man Government announced its intention to replace the DPC regime with a new system, to be known as the Attribution Regime for Individuals (‘‘ARI’’). This has been approved by the Isle of Man parliament, Tynwald, and introduced via The Income Tax (Attributed Profits) Temporary Taxation Order 2007, which states that ARI will replace DPC for accounting periods commencing after 6 April 2008. It is not anticipated that the ARI regime will materially affect the Company’s taxation position in the Isle of Man as outlined above. UK Resident Shareholders An Isle of Man company has no requirement to make any deduction or withholding of tax on dividends paid to shareholders resident outside of the Isle of Man. Any dividends paid from income subject to tax at 10 per cent. will carry a 10 per cent. tax credit. This tax credit will not be refundable where the recipient is a non Isle of Man resident company or individual. Therefore UK resident shareholders will not incur any liability to Isle of Man non-resident income tax in relation to Ordinary Shares held by them and the Company will not become liable to make any withholding on payments made to a non-resident of the Isle of Man.

217 11.2 United Kingdom The Company The Company is resident in the UK by virtue of its central management and control being exercised in the UK. The Company is therefore liable for UK taxation on its worldwide income and chargeable gains. UK Resident Shareholders (a) Taxation of Dividends on Ordinary Shares There is no further UK income tax charge in respect of dividends for United Kingdom domiciled and ordinarily resident individual Shareholders, other than taxpayers who are liable to income tax at the higher rate. A higher rate taxpayer will be liable to UK income tax on dividends received from the Company (to the extent that, taking the dividend as the top slice of his income, it falls above the threshold for the higher rate of income tax) at the upper dividend rate (currently 32.5 per cent.) A notional tax credit of 10 per cent. will apply to the dividend, leaving a further income tax liability equal to 25 per cent. of the net dividend received. United Kingdom resident Shareholders who are not liable to income tax on their income will not be subject to tax on dividends received from the Company. UK resident corporate shareholders will not normally be liable for corporation tax on any dividends paid by the Company. (b) Taxation of Capital Gains Any gains on disposals by UK resident or ordinarily resident holders of the Ordinary Shares or holders of the Ordinary Shares who carry on a trade in the UK through a permanent establishment with which their investment in the Company is connected may, depending on their individual circumstances and subject as mentioned below, give rise to a liability to United Kingdom taxation on capital gains. On a disposal prior to 6 April 2008 by an individual Shareholder who is resident or ordinarily resident in the UK for tax purposes, the Ordinary Shares may attract taper relief which reduces the amount of chargeable gain according to how long, measured in years, the Ordinary Shares have been held. A Shareholder which is a body corporate resident in the UK for taxation purposes will benefit from indexation allowance which, in general terms, increases the capital gains tax base cost of an asset in accordance with the rise in the Retail Prices Index. (c) Stamp Duty and Stamp Duty Reserve Tax The following comments are intended as a guide to the general stamp duty and stamp duty reserve tax position and do not relate to persons such a dealers, intermediaries and persons connected with voluntary arrangements or clearance services, to whom special rules apply. No UK stamp duty, or stamp duty reserve tax, will be payable on the issue of the Ordinary Shares. UK stamp duty (at the rate of 0.5 per cent. of the amount of the value of the consideration for the transfer, rounded up where necessary to the nearest £5) is payable on any instrument of transfer of the Ordinary Shares executed within, or in certain cases brought into, the UK. Provided that the Ordinary Shares are not registered in any register of the Company kept in the UK, any agreement to transfer the Ordinary Shares will not be subject to UK stamp duty reserve tax. (d) Other UK tax considerations The listing of the Ordinary Shares on the Official List will mean that the Ordinary Shares will no longer be classed as shares in an unlisted company for the purposes of various tax reliefs, including inheritance tax business property relief, capital gains tax taper relief and the enterprise investment scheme, among others. Any person who is in any doubt as to his or her tax position or who may be subject to tax in any jurisdiction other than the United Kingdom should consult their own professional adviser. 12. WORKING CAPITAL 12.1 In the opinion of the Directors, having made due and careful enquiry, the working capital available to the Group is sufficient for its present requirements, that is for at least the next twelve months from the date of Admission.

218 13. MATERIAL CONTRACTS 13.1 The following contracts, not being contracts entered into in the ordinary course of business, have been entered into by the Group (a) during the two years immediately preceding the date of this document and are or may be material or (b) contain provisions under which the Company or its subsidiaries has any obligation or entitlement which is material to the Group as at the date of this document: 13.1.1 The exploration licences and agreements summarised in part 1 of this document. 13.1.2 A financial adviser, sponsor and broker engagement letter dated 10 January 2008 between the Company and Arden Partners, pursuant to which the Company has appointed Arden Partners as its financial adviser, sponsor and broker in connection with the admission of the Ordinary Shares to the Official List. The engagement letter contains certain obligations, undertakings and indemnities from the Company which are customary for an agreement of this nature. The Company has agreed to pay Arden Partners a fee of £100,000 in connection with their appointment. 13.1.3 A financial adviser and broker engagement letter dated 7 February 2008 between the Company and Arden Partners, pursuant to which the Company has appointed Arden Partners as its financial adviser and broker on an ongoing basis subsequent to Admission. The engagement letter contains certain obligations, undertakings and indemnities from the Company which are customary for an agreement of this nature. The Company has agreed to pay Arden Partners a retainer of £40,000 per annum in connection with their engagement. The letter includes an acknowledgment that the nominated adviser and broker agreement detailed in sub-paragraph 13.1.6 below will terminate upon Admission. 13.1.4 A placing agreement dated 25 May 2007 between the Company and Arden Partners pursuant to the terms of which Arden Partners agreed to use its reasonable endeavours to procure placees to subscribe for up to 4,964,540 Ordinary Shares at a price of 423p per Ordinary share. Pursuant to the terms of the agreement the Company gave certain warranties and indemnities customary for an agreement of this nature in favour of Arden Partners, unlimited in time and amount. The Company paid Arden Partners a commission of 4 per cent. of the aggregate value of the placing price for which Ordinary Shares were subscribed. 13.1.5 A placing agreement dated 9 February 2006 between the Company and Arden Partners pursuant to the term of which Arden Partners agreed to use its reasonable endeavours to procure placees for 5,204,660 new Ordinary Shares at a price of 283p per Ordinary Share or failing which, to subscribe itself, as principal, for such Ordinary Shares. Pursuant to the terms of the agreement the Company gave certain warranties and indemnities customary for an agreement of this nature in favour of Arden Partners, unlimited in time and amount. The Company paid Arden Partners a commission of 4 per cent. of the aggregate value of the placing price for which the Ordinary Shares were subscribed. 13.1.6 A nominated adviser and broker agreement dated 2 June 2005 between the Company, the Directors and Arden Partners pursuant to which the Company appointed Arden Partners to act as nominated adviser and broker to the Company for the purposes of AIM. The Company agreed to pay Arden Partners an annual fee of £40,000 for its services as nominated adviser and broker. The agreement continues for an indefinite period from 2 June 2005 and is subject to termination, inter alia, by either the Company or Arden Partners on the giving of not less than one month’s prior written notice. The agreement will terminate forthwith upon the Ordinary Shares ceasing to be admitted to trading on AIM.

14. RELATED PARTY TRANSACTIONS The Company has not entered into any related party transactions.

15. LITIGATION 15.1 Neither the Company nor any member of the Group is or has been involved in any governmental, legal or arbitration proceedings (including any such proceedings which are pending or threatened of which the Company is aware) which may have or have had during the 12 months prior to the date of this document, a significant effect on the Group’s financial position or profitability.

219 16. SIGNIFICANT CHANGE Save as disclosed in part 1 of this document in relation to the gas discovery at D3 and the spudding of the second exploration well as announced 13 February 2008 (under the heading ‘Block D3 — Exploration Licence’ on page 31), the successful well test carried out on the Oza field in December 2007 (under the heading ‘Oza Field’ on page 36), and the acquisition and sale of HOEC shares (under the heading ‘Shareholding in Hindustan Oil Exploration Company Limited’ on page 36), there has been no significant change in the financial or trading position of the Group since 30 September 2007, being the date to which its most recent audited financial information has been published.

17. PROPERTY, PLANT AND EQUIPMENT 17.1 Further to the material tangible fixed assets described in part 1 the Group has the following material tangible fixed assets including leasehold properties as follows: Location Use Tenure Term Lincoln House, Offices Leasehold 9 December 2006- Hammersmith Road, 21 June 2012 London Plot 180B Moshood Residential Leasehold 1 November 2006- Olugbani Street, 30 October 2008 Victoria Island, Lagos 5th Floor, Offices Leasehold 1 July 2007- Westminster Building, 30 June 2010 108, Dr, Radhakrishna Sala, Chennai 7th Floor, Offices Leasehold 1 July 2007- Westminster Building, 30 June 2010 108, Dr, Radhakrishna Sala, Chennai

18. GENERAL 18.1 There are no patents or other intellectual property rights, licences or particular contracts which are of fundamental importance to the Group’s business, except as set out in part 1 of this document. 18.2 The total costs and expenses in connection with or incidental to the Admission (including fees) are estimated to be approximately £500,000, excluding VAT. 18.3 The information sourced from third parties has been accurately reproduced and so far as the Company is aware and has been able to ascertain from information published by such third parties, no facts have been omitted which would render the reproduced information inaccurate or misleading. 18.4 The Company’s auditors for the periods covered by part 5 of this document were Horwath Clark Whitehill LLP of St. Bride’s House, 10 Salisbury Square, London EC4Y 8EH, a member of the Institute of Chartered in England and Wales. 18.5 Horwath Clark Whitehill LLP has given and not withdrawn its written consent to the issue of this document with the inclusion of its Accountants’ Reports in part 5 of this document and the references to such reports and to its name in the form and context in which they are included and accepts responsibility for such reports in accordance with the Prospectus Rules. 18.6 Gaffney Cline & Associates Ltd. has given and not withdrawn its written consent to the issue of this document with the inclusion of its Competent Person’s Report in part 3 of this document and the references to such report and to its name in the form and context in which they are included. 18.7 Arden Partners has given and not withdrawn its written consent to the issue of this document with the references to its name in the form and context in which such references are included.

220 18.8 For the purposes of Prospectus Rule 5.5.3R(2)(f), GCA is responsible for the Competent Person’s Report contained in part 3 of this document and declare that it has taken all reasonable care to ensure that the information contained in this report is, to the best of its knowledge, in accordance with the facts and contains no omission likely to affect its import. 18.9 At close of business on the business day prior to Admission, the admission of the Ordinary Shares to AIM will be cancelled.

19. AVAILABILITY OF DOCUMENTS 19.1 Copies of the following documents may be inspected at the office of the Company Lincoln House, 137-143 Hammersmith Road, London W13 0QL during usual business hours on any weekday (Saturdays, Sundays and public holidays excepted) for a period of 12 months following Admission: 19.1.1 the memorandum of association and Articles of the Company; 19.1.2 the consolidated financial statements of the Group for the nine months period ended 30 September 2007 and the financial years ended 31 December 2006, 31 December 2005 and 31 December 2004; 19.1.3 the consent letters referred to in paragraph 18 above; 19.1.4 the Competent Person’s Report; 19.1.5 the indebtedness statement at part 5 of this document; 19.1.6 the Accountants Reports at part 5 of this document; and 19.1.7 this document. Date: 15 February 2008

221 PART 7 — DEFINITIONS AND GLOSSARY

The following definitions apply throughout this document, unless the context otherwise requires:

‘‘Acts’’ Isle of Man Companies Acts 1931 to 2004

‘‘Admission’’ the admission of the Ordinary Shares to the Official List and to trading on the London Stock Exchange’s main market for listed securities becoming effective

‘‘AGIP’’ Nigerian AGIP Oil Company Limited

‘‘AIM’’ the market of that name operated by the London Stock Exchange

‘‘Arden Partners’’ Arden Partners plc

‘‘Articles’’ the articles of association of the Company adopted on 4 February 2008

‘‘Audit Committee’’ the audit committee of the Company

‘‘Bayelsa’’ Bayelsa Oil Company Limited

‘‘certificated’’ or ‘‘in certificated form’’ the description of a share or security which is in certificated form (that is, not in CREST)

‘‘City Code’’ the City Code on Takeovers and Mergers issued by the Panel (as amended from time to time)

‘‘Combined Code’’ the Combined Code on Corporate Governance published in June 2006 by the Financial Reporting Council being the key source of corporate governance recommendation for companies listed on the Official List

‘‘Company’’ or ‘‘Hardy Oil and Gas’’ or Hardy Oil and Gas plc ‘‘Hardy’’

‘‘Competent Person’s Report’’ or ‘‘CPR’’ the report on the Company’s assets by GCA as set out in Part 3 of this document

‘‘CPCL’’ Chennai Petroleum Company Limited, formerly known as Madras Refinery Limited

‘‘CREST’’ the relevant system (as defined in the CREST Regulations) for the paperless settlement of share transfers and the holding of shares in uncertificated form which is administered by CRESTCo

‘‘CRESTCo’’ Euroclear UK & Ireland Limited, the operator of CREST

‘‘CREST Regulations’’ UK Uncertificated Securities Regulations 2001

‘‘D3’’ Licence KG-DWN-2003/1

‘‘D9’’ licence KG-DWN-2001/1 awarded under NELP III

222 ‘‘Directors’’ or ‘‘Board’’ the directors of the Company for the time being, whose names appear on page 16 of this document

‘‘Disclosure and Transparency Rules’’ the disclosure and transparency rules made by the UKLA in accordance with section 73(A)(3) of FSMA relating to the disclosure of information in respect of financial instruments which have been admitted to a regulated market

‘‘FSA’’ the Financial Services Authority in its capacity as the competent authority for the purposes of Part VI of FSMA and in the exercise of its functions in respect of admission to the Official List otherwise in accordance with Part VI of FSMA

‘‘FSMA’’ the Financial Services and Markets Act 2000 of England and Wales, as amended

‘‘GAIL’’ Gas Authority of India Limited

‘‘GCA’’ Gaffney, Cline & Associates Ltd.

‘‘GDP’’ Gross domestic product

‘‘GOI’’ Government of India

‘‘Group’’ the Company and its subsidiaries

‘‘GS-01’’ licence GS-OSN/2000/1 awarded under NELP II

‘‘HEPI’’ Hardy Exploration & Production (India) Inc.

‘‘HOEC’’ Hindustan Oil Exploration Company Limited

‘‘HON’’ Hardy Oil Nigeria Limited

‘‘IFRS’’ International Financial Reporting Standards

‘‘ISIN’’ International Securities Identification Number GB00B09MB366

‘‘Listing Rules’’ the rules and regulations made by the UKLA pursuant to Part VI of FSMA, as amended from time to time

‘‘London Stock Exchange’’ London Stock Exchange plc

‘‘Millenium’’ Millenium Oil and Gas Company Limited

‘‘MOPNG’’ Ministry of Petroleum and Natural Gas of India

‘‘NELP’’ New Exploration Licencing Policy of MOPNG

‘‘NNPC’’ Nigerian National Petroleum Corporation

‘‘Nominations Committee’’ the nominations committee of the Company

‘‘ONGC’’ Oil and Natural Gas Corporation Limited

‘‘OPEC’’ Organisation of the Petroleum Exporting Countries

223 ‘‘Option’’ an option over Ordinary Shares granted pursuant to the Share Option Scheme

‘‘Ordinary Shares’’ the ordinary shares of US$0.01 each in the capital of the Company

‘‘Panel’’ the UK Panel on Takeovers and Mergers

‘‘Prospectus Directive’’ EU Prospective Directive (2003/71/EC)

‘‘Prospectus Rules’’ the rules made for the purposes of Part VI of FSMA in relation to offers of Securities to the public and admission of securities to trading on a regulated market

‘‘PY-3’’ licence CY-OS 90/1

‘‘Reliance’’ Reliance Industries Limited

‘‘Remuneration Committee’’ the remuneration committee of the Company

‘‘Senior Managers’’ the managers of the Company whose names are set out at paragraph 2 of part 2

‘‘Shareholders’’ holders of Ordinary Shares

‘‘Share Option Scheme’’ the Hardy Oil and Gas plc 2005 Unapproved Share Option Scheme details of which are set out in paragraph 6 of part 6 of this document

‘‘SPDC’’ the Shell Petroleum Development Company of Nigeria Limited

‘‘subsidiary’’ and ‘‘subsidiary have the meanings respectively ascribed to them by the UK undertaking’’ Act

‘‘TATA’’ TATA Petrodyne Private Limited

‘‘UK’’ or ‘‘United Kingdom’’ the United Kingdom of Great Britain and Northern Ireland

‘‘UK GAAP’’ the generally accepted accounting principles in the UK

‘‘UKLA’’ the FSA acting in its capacity as the competent authority for the purposes of Part VI of FSMA

‘‘uncertificated’’ or ‘in uncertificated recorded on the relevant register of the share or security form’’ concerned as being held in uncertificated form in CREST and title to which, by virtue of the CREST Regulations, may be transferred by means of CREST

‘‘Uncertificated Regulations’’ the Isle of Man Uncertificated Securities Regulations 2005

‘‘US’’ or ‘‘USA’’ or ‘‘United States’’ United States of America, its territories and possessions, any state of the United States of America and the District of Columbia and all other areas subject to its jurisdiction

‘‘US$’’ US Dollars

224 GLOSSARY OF TERMS The following glossary of terms applies throughout this document, unless the context otherwise requires: AAPG American Association of Petroleum Geologists API American Petroleum Institute Associated gas is a natural gas which is found in association with crude oil, either dissolved in the oil or as a cap of free gas above the oil Bcf billion cubic feet (of gas) bbl barrels of oil bopd barrels of oil per day Bscf billion square cubic feet bwpd barrels of water per day (injected volumes) Brent a benchmark crude oil, the most commonly traded North Sea crude oil Contingent as defined in Appendix II contained in part 3 of this document Resources Contractor the companies with a working interest in the field or PSC CoS geological chances of success Cost Oil portion of oil production which the Contractor is entitled to take for the recovery of all costs expended by the Contractor under the terms of the PSC DST drill stem testing DWT dead weight tonne Entitlement share of produced hydrocarbons that the Contractor is entitled to take under the terms of the PSC consisting of Cost Oil plus Profit Oil GIIP gas initially in place GOR gas oil ratio GTL gas to liquids JOA joint operating agreement km kilometre km2 square kilometres Lead project associated with a potential accumulation that is currently poorly defined and requires more acquisition and/or evaluation in order to be classified as a Prospect LNG liquefied natural gas M thousand m metres MDRT measured depth from the rotary table MM million MMscfd million standard cubic feet per day MMstb million stock tank barrels (of oil) NPI net participating interest NPV net present value

225 NWI net working interest OML oil mining licence Operator party nominated under the JOA/PSC to operate the approved licence under good oil field practice P10 at least ten per cent. probability of occurrence (often equivalent to Proved Reserves plus Probable Reserves plus Possible Reserves or high volume estimate) P50 at least fifty per cent. probability of occurrence (often equivalent to Proved Reserves plus Probable Reserves or best volume estimate) P90 at least ninety per cent. probability of occurrence (often equivalent to Proved Reserves, or low volume estimate) Possible Reserves as defined in Appendix II contained in part 3 of this document Profit Oil portion of oil production for which the Contractor is entitled to take after recovery of Cost Oil as compensation for services rendered by the Contractor under the terms of the PSC Probable Reserves as defined in Appendix II contained in part 3 of this document Prospect a project associated with a potential accumulation that is sufficiently well-defined to represent a viable drilling target Prospective as defined in Appendix II contained in part 3 of this document Resources Proved Reserves as defined in Appendix II contained in part 3 of this document psi pounds per square inch SPE Society of Petroleum Engineers SPEE Society of Petroleum Evaluation Engineers scf standard cubic feet stb stock tank barrels stb/d stock tank barrels per day STOIIP stock tank oil initially in place Tcf trillion cubic feet (of gas) WPC World Petroleum Council

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Capital Systems 31356