HDY.L Regulatory News (HDY)

For immediate release 16 March 2011

Hardy Oil and Gas plc

("Hardy", "the Company" or "the Group")

2010 Preliminary Results

Hardy Oil and Gas plc (LSE: HDY), the oil and gas exploration and production company with assets in India, announces its preliminary results for 2010, provides an outlook for 2011 and publishes an updated competent persons report.

*All financial amounts in US dollars unless otherwise stated.

2010 was an active year for the Company on many fronts, including the following:

Operational highlights

·; PY-3 - Gross daily production from the PY-3 field averaged 3,156 barrels per day (bbld) in 2010 (net: 568 bbl)

·; D3 - Announced the fourth consecutive natural gas discovery (Dhirubhai 52) which encountered a gross gas pay zone of 37.5 m in Pliocene aged sands

·; D3 - A proposal for the declaration of commerciality of the Dhirubhai 39, 41 and 52 natural gas discoveries was submitted to the DGH at the beginning of 2011

·; D9 - The second exploration well recorded gas shows while drilling but MDT testing of the penetrated sands indicated high water saturation. The well proved the existence of reservoir quality sands and a petroleum system in this frontier, deep water block. Following MDT testing the well was plugged and abandoned

·; GS-01 - A proposal for the declaration of commerciality of the Dhirubhai 33 natural gas discovery was submitted to the DGH in mid 2010

·; CPR - An updated Competent Person's Report has been undertaken;

o Net entitlement reserves (2P) 2.1 mmbbl (2009: 2.5 mmbbl)

o Net contingent resources (2C) 174 bcf, 0.2 mmbbl (2009: 158 bcf)

o Net risked prospective resources (best estimate): D3 - 396 bcf (2009: 387 bcf), D9 - 466 bcf, 18 mmbbl (2009: 520 bcf, 18 mmbbl). Aggregated risked prospective resources have been derived by Hardy and are not aggregated or provided as risked volumes by GCA

o The full report has been posted on the Company's website www.hardyoil.com

In 2010, Hardy enjoyed a significant turnaround in its financial performance

Financial Highlights

·; Profit before taxation from continuing operations of $2.2 million (2009: loss $7.4 million)

·; Cash flow from continuing operations of $4.0 million† (2009: Cash deficiency $3.6 million†)

·; Capital expenditure of $6.1 million (2009: $13.6 million)

·; Sold Nigerian assets for net proceeds of $4.3 million

·; Equity issue in December 2010 raising $9.5 million (2009: $15.2 million)

·; Cash and short-term investments at 31 December 2010 of $36.5 million (2009: $30.5 million) and no long-term debt

† Before changes in non cash working capital, tax paid, interest and investment income and finance costs

Outlook

2011 promises to be an active year for Hardy:

·; D3 - The joint venture will work with the GOI to advance the proposal for declaration of commerciality. The joint venture has also submitted an appraisal programme for the Dhirubhai 44 gas discovery which is being reviewed by DGH.

·; D3 - Four of the six commitment wells have now been drilled on the D3 exploration block. The Company anticipates the drilling of at least one of the several material undrilled prospects in 2011.

·; GS-01 - Hardy expects to receive approval of commerciality in respect of the application made for the GS-01 Dhirubhai 33 natural gas discovery, in the near future.

·; PY-3 - Hardy will seek to secure approval from its partners and the GOI to drill two further producing wells in 2012, and upgrade the production facilities to include artificial lift to extend the field life.

·; D9 - Hardy is working with the operator to update plans for this extensive block, which has considerable prospectivity.

Commenting on the results, Paul Mortimer, Chairman of Hardy said:

"During 2010, the Company accomplished a number of key objectives and realised a significant improvement in its financial performance.

BP's announced acquisition from Reliance of an interest in the Krishna Godavari Basin is a welcome development. BP brings considerable additional skills and resources to the joint ventures and we believe that their participation is an endorsement of the quality of our exploration assets."

For further information please contact:

Chairman's Statement

Corporate overview

During 2010, the Company accomplished a number of key objectives and realised a significant improvement in financial performance. The divestment of our Nigerian operations has resulted in freeing up of capital and management resources to focus on exploiting the full potential of our portfolio in India. Hardy's exploration programme on the Company's two blocks in the Krishna Godavari Basin progressed with the drilling of two further exploration wells. As a result of this activity, we were delighted to announce the fourth consecutive gas discovery in D3. We have subsequently submitted a declaration of commerciality proposal, for the Dhuribhai 39, 41 and 52 discoveries on this block, to the GOI for review. The second exploration well drilled in 2011 was on our D9 asset (KG-D9-B3) which recorded gas shows while drilling though good quality sands which, on testing, proved to be water bearing and the well was plugged and abandoned.

Despite fluctuating market conditions in 2010, the Company was pleased to raise $9.5 million in a successful equity placing at the end of 2010. The funds raised provide the Company with a strong working capital position with which to fund its planned work activity and provides some flexibility to explore other business development opportunities. We are delighted with the continued support of our core shareholder base.

Key financial results

Revenue was up from $7.7 million in 2009 to $12.9 million in 2010 due to higher production levels (there was an unplanned extended shut-in of the PY-3 field in 2009) and a higher average realised oil price. Administrative expenses were down significantly compared to 2009, resulting in an operating profit from continuing operations of $1.9 million in 2010 compared with an operating loss of $7.5 million in 2009.

The Company started 2010 with cash reserves of $30.5 million. Net cash generated from continuing operating activities (before changes in non cash working capital, tax paid, interest and investment income and finance costs) was $4.0 million. Cash used for investing activities amounted to $6.1 million in 2010 for the drilling of exploration wells on D3 and D9. An equity issue in December 2010 resulted in net cash infusion of $9.5 million augmenting our working capital. As a result, the Company's cash reserves at the end of 2010 were $36.5 million. The Company remains in a strong financial position and has no long-term debt.

Strategy

Hardy has a clear objective to create significant shareholder value through an India focused upstream exploration and development strategy. We believe that the India sedimentary basins are underexplored and, as our results in the Krishna Godavari Basin have shown, significant accumulations of hydrocarbons remain to be found. India's economy is expected to continue its impressive growth and, as a result, the country's energy consumption, along with its infrastructure, will materially increase, far exceeding current domestic supply. Our perception has been reinforced recently by the entry of BP into this exploration province.

India's natural gas carrying capacity is expected to increase fourfold by 2015 to 490 mmscmd (length 24,000 km). Natural gas prices in India have progressively increased over the past ten years by over 250 per cent. With demand growth projected to continue, we anticipate price inflation to continue at pace. The combination of prospective underexplored basin's located within close proximity to a growing consumer market, presents an attractive upstream investment opportunity.

In the recently announced transaction between Reliance Industries Limited (Reliance) and BP, (which represents one of the biggest single foreign direct investments in India) BP stated that the transaction met with their strategy to increase exposure to growing energy markets. BP's Energy Outlook 2030 report states that energy consumption in India has grown by 190 per cent over the past 20 years and is likely to grow by 115 per cent over the next 20 years, a rate of over 4 per cent per annum. Gas is expected to be the fastest growing fossil fuel, with demand growing at a rate of nearly 5 per cent per annum between 2010 and 2030. India's gas consumption was 5.0 bcfd in 2009 and is estimated to be 6.1 bcfd in 2010 (comprising 4.9 bcfd production plus 1.2 bcfd LNG imports). Total Indian gas consumption is projected to grow to 12.5 bcfd by 2025, and exceed 15 bcfd by 2030.

Hardy is well positioned to participate in this growth due to its prospective exploration asset portfolio, an established offshore operating track record, and strong technical, financial and commercial capabilities critical to upstream exploration and production. We believe that the Company has a sustainable platform to continue to participate in the India growth story. We also recognise that the addition of short to medium term production would enhance our prospects and management is considering various options to achieve this.

Over the past four years, our strategy has produced six gas discoveries from eleven exploration wells. The declaration of commerciality submissions made in 2010 are the next step in reaching our ultimate objective of realising the monetisation of our exploration efforts. Today we view the D3 exploration block with considerable optimism and continue to believe that our existing exploration portfolio offers significant organic growth potential for the Company. The arrival of BP as a partner in several blocks can only enhance the prospect of early development of our discoveries.

Governance

In 2010 Mr Yogeshwar Sharma succeeded Mr Sastry Karra as Chief Executive Officer of Hardy. Mr Karra remained as a Non-Executive Director until November 2010. Messrs Sharma and Karra co-founded Hardy and the Board wishes to thank Sastry for his immense contribution and sound leadership to Hardy over the past thirteen years and we wish him well in his future endeavours.

Following an appraisal of the Board and its members in 2009, the Board considers that its current structure, competencies and remuneration policies are appropriate for a publicly listed, early stage, oil and gas exploration company. In addition to a formal annual evaluation, the Board continually reviews the appropriateness of the Board's composition, structure and internal processes as the Company evolves.

Risk management

In 2010, the Board adopted a formal risk and uncertainties review process, involving the generation, identification of key risks and the formulation of mitigation strategies by the Company's senior management team. Through the review process the following principal risks for 2011 were identified;

·; Exploration risk - The Company's current strategy involves offshore exploration and production activities. Exploration is intrinsically very uncertain and whilst substantial improvements in predictive/interpretation technology have reduced this uncertainty, it cannot be eliminated.

·; Offshore drilling - the Company is directly and indirectly involved in drilling offshore wells. In the event of a loss of control of a well could have a material negative impact on the Company.

·; High-cost environment - The effect of a high cost environment is the compounded financial impact of operational delays during drilling and other operations.

·; Production - The Company's sole source of revenue is from a single producing oil well in the PY-3 field. An unexpected shut-in would have a material impact on the Company's ability to generate cash flow in the short to medium term.

·; CY-OS/2 arbitration - In 2010 the Company and the GOI referred the dispute regarding our claim of entitlement to a licence extension for arbitration. Should the arbitration ruling not be in Hardy's favour the block would stand relinquished and impairment testing will be required.

Year end audit

The auditors have provided an emphasis of matter comment in their audit report with reference to the uncertainty concerning the Group's request for an extension of its exploration licence in block CY-OS/2 as disclosed in note 7 to the consolidated financial statements.

Going concern

Having regard to the Company's existing working capital position and its ability to raise potential financing, the Directors are of the opinion that the Group has adequate resources to enable it to undertake its planned work programme of exploration, appraisal and development activities over the next 12 months.

Outlook

In 2011 we aim to continue to create significant shareholder value by focusing on high impact exploration in India. We are particularly looking forward to the continued exploration of our D3 block which, with four consecutive gas discoveries, is in the early stage of exploration with significant upside potential. We expect to drill at least two further exploration wells in the Krishna Godavari Basin by the end of 2011.

BP's announced acquisition from Reliance of an interest in the Krishna Godavari Basin is a welcome development. At the time of the announcement, BP noted that the transaction will allow them to access the most prolific gas basin in India (Krishna Godavari) and secure a place in the fast growing Indian gas markets. We believe that their participation is also an endorsement of the quality of our exploration assets and we share their outlook of India's substantial natural gas demand growth potential. We join our partner Reliance in welcoming BP's participation in our exploration blocks in the Krishna Godavari Basin.

Our existing exploration portfolio in the Krishna Godavari Basin remains the core to our organic growth. The Krishna Godavari Basin is an emerging world-class petroleum province and, together with rapidly improving Indian gas pipeline infrastructure and high demand for gas, the prospects for the economic development of gas resources in this area are excellent. The Company is well positioned to see itself through its key exploration activities in 2011.

E.P. Mortimer

Chairman

15 March 2011

Chief Executive's Statement

Overall our efforts in 2010 resulted in a number of positive developments including a significant turnaround in the Company's financial results, the disposal of our Nigerian assets, and the drilling of two deepwater exploration wells resulting in a natural gas discovery. In 2011, we will continue to build on this positive momentum with further exploration drilling in the Krishna Godavari Basin and secure partner approval to set in place PY-3 development drilling in 2012.

Execution of Strategy

As a result of the disposal of our Nigerian assets in October 2010, the Company is now fully committed to its India focused strategy with a mandate of creating significant long-term shareholder value through the exploration and appraisal of our existing exploration portfolio. With India's robust economic growth and attractive upstream fiscal and regulatory regime, the Company continues to view India as an excellent investment opportunity for upstream oil and gas activity.

The highlight of 2010 was the fourth consecutive natural gas discovery on the Company's D3 asset in the Krishna Godavari Basin. Substantial independent evaluation and interpretation activities on D3 were undertaken by the Company in 2010. This independent work and continued drilling success have heightened our enthusiasm for the substantial prospectivity of the D3 exploration licence. Although we have four discoveries to date, we remain in the relatively early stages of exploration as there are many untested play types and an expanding prospect inventory.

The submission of declaration of commerciality on two blocks (D3 & GS-01) is further endorsement of our India focused strategy of de-risking our exploration assets and minimise the time cycle from discovery to development.

Maintaining and enhancing the Company's technical and commercial competencies is an integral component for the successful execution of our strategy. In this regard, we were pleased to be able to announce the appointment of William Satterfield as Technical Director of HEPI. Mr Satterfield has extensive international upstream exploration, production and business development operating experience and has made a positive impact on our organisation. We will continue to look to enhance our organisation's core technical, financial and commercial competencies to maintain the Company's platform to capture the growth and value creating opportunities unique to India's upstream sector.

Exploration Highlights

The highlight of our 2010 exploration programme was the drilling of two deep water wells on the Company's Krishna Godavari Basin blocks. As a result, the Company announced the fourth consecutive natural gas discovery (Dhirubhai 52) on the Company's D3 exploration block in the Krishna Godavari Basin. The Company also submitted a proposal for the declaration of commerciality of the Dhirubhai 39, 41 and 52 natural gas discoveries on the D3 exploration block.

The second exploration well on the D9 exploration block recorded high percentage of gas while drilling through reservoir quality sands, however MDT testing recorded high saturation of water and as a result the well was plugged and abandoned. The well has proven the presence of a petroleum system on the North-Central portion of the block. The cost of this well, following MDT testing, was below budget due to efficient drilling.

In July 2010, the Cabinet Committee on Economic Affairs of the Government of India approved the grant of a drilling moratorium of three years up to 31 December 2010. As a result, the exploration phase I for the D3 licence is extended into 2013 and the D9 licence can be extended by up to 12 months. The D9 joint venture has subsequently applied for a six month extension in order to complete the minimum work commitment of two further exploration wells.

Resource Potential

The Company has provided an updated CPR, undertaken by Gaffney, Cline & Associates Ltd (GCA), effective 31 December 2010. Set out below is a summary of the highlights of the report;

·; Reserves - Total net proven plus probable (2P) oil reserves amount to 2.1 mmbbl (2009: 2.5 mmbbl).

·; Contingent Resources - Total net contingent gas resources amount to 174 bcf (2009: 158 bcf). Total net contingent oil resources amount to 0.19 mmbbl (2009: nil).

·; Prospective Resources* (Gas) - Total net risked best estimate gas prospective resources for D3 increased to 396 bcf (2009: 387 bcf). The total net risked best estimate gas prospective resources for D9 decreased to 466 bcf (2009: 520 bcf).

·; Prospective Resources* (Oil) - Total net risked best estimate oil prospective resources for D9 was unchanged at 18 mmbbl. 

·; The 2009 comparable estimates do not included volumes associated with Hardy Oil (Africa) limited which was sold during 2010.

*Aggregated risked prospective resources have been derived by Hardy and are not aggregated or provided as risked volumes by GCA

A summary of the 2011 report, providing a block by block breakdown, is provided at the end of this announcement and the complete report can be downloaded from Hardy's website www.hardyoil.com.www.hardyoil.com

Development and Production

During 2010, the Company operated PY-3 field produced 1.15 mmbbl of oil compared with 0.56 mmbbl for 2009. The increase in production is principally attributable to the uninterrupted production from the field and better than expected performance of the field water flood.

The PY-3 field re-commenced production in January 2010 (following an unplanned six month shut-in) at an initial gross rate of 3,336 bbld and the field averaged 3,156 bbld (net: 568 bbld) through the year. For 2011, the PY-3 field is forecast to produce at an average daily rate of 3,100 bbld (net: 558 bbld).

The PY-3 production facilities are currently contracted through April 2011 and we are working closely with our partners and contractors to establish a longer-term arrangement for the offshore production facilities. This approval is expected in conjunction with the budget approval to drill two additional production wells in 2012.

Financial Highlights

As a result of sustained production from PY-3, the Company sold 158 mbbl of oil at an average price of $81.71 per bbl resulting in operating revenue of $12.9 million. As a result, Hardy enjoyed an increase in net cash generated from continuing operations from a deficiency of $3.6 million in 2009 to a surplus of $4.0 million, a turn-around of $7.6 million.

Key Partnerships

In 2010, Hardy increased its proactive involvement with respect to our non-operated assets, working closely with our strategic partners in India, contributing independent assessments in conjunction with collaborative dialog. The Company interacts on a regular basis with its partners at multiple levels, to ensure that our goals and objectives are addressed and to facilitate planning of upcoming work programme schedules. Maintaining open and substantive relationships with existing partners and other key stakeholders in the upstream oil and gas sector in India are critical to the execution of the Company's strategy.

In early 2011, it was announced that BP will become a joint venture partner with Hardy and Reliance in both of our Krishna Godavari Basin blocks and the Assam block. At the time of the announcement, Reliance described BP as one of the finest deep water exploration companies in the world. They bring considerable additional skills and resources, backed by a quality research and development group, to our partnership. The combined skills of our companies will be focused on finding and developing more hydrocarbons in the deep water blocks of India and significantly contributing to India's energy security. We welcome BP and look forward to working with them and Reliance on our joint venture projects in the future.

2011 Programme

In 2011 we expect to drill at least two wells, one on each of our Krishna Godavari Basin blocks. As mentioned earlier, the fourth successive discovery on our D3 block has enhanced expectations of this promising block. Further seismic processing is required over the toe-thrust area (north east) prior to drilling in this area. The processing is expected to be ongoing through the first half of 2011.

As a result of the four consecutive discoveries that have been made on D3, this block now singularly stands out as the premier asset of Hardy. We have identified 26 prospects or leads with an average size of 233 bcf. We remain in the early stages of exploration on this block and with six different play types present; we view this asset with great optimism.

We firmly believe in the prospectivity of the D9 Block and although the KG-D9-B3 well was plugged and abandoned, we are encouraged that the well encountered reservoir quality sand and provided evidence of a working petroleum system. Hardy looks forward to recommencing drilling operations on this block later in the year.

We currently have submitted declaration of commerciality proposals on two blocks - D3 and GS-01. These are under review with the GOI and we expect to work closely with the operator to advance these projects in 2011.

For the Company's two operated assets, we are focused on securing budget approval for the development drilling programme proposed for the PY-3 field. Budget approval will need to be secured by mid 2011 to meet our objective of commencing drilling in 2012, and upgrade the production facilities to include artificial lift to extend the field life. The CY-OS/2 arbitration process is ongoing and further activity on this block is differed until the arbitration tribunal has made its ruling.

Overall we are enthusiastic about 2011, as we continue our efforts to de-risk our exploration portfolio in the Krishna Godavari Basin in India through further exploration drilling. We are committed to continue with our disciplined capital allocation strategy by focusing on activities that have the potential to deliver a significant increase in shareholder value.

Beyond the Company's existing portfolio, the Company will continue to evaluate and assess potential acquisitions in India that offer short to medium term production additions and complement our existing assets and organisational competencies.

Staff

The Company made good progress in 2010 and we have generated some positive momentum leading into 2011. This can, for a large part, be attributed to our staff in India and the United Kingdom. The Group has demonstrated a tremendous level of dedication and commitment, having continued to work professionally and efficiently to meet our objectives in a challenging environment. In 2010 we were successful in recruiting some key individuals into our senior management team and we will endeavour to compliment them with additional mid-level technical and commercial expertise though 2011. This year, our India team will be relied upon to drive the core of our business and we will look to continue to retain and enhance our technical, operational and management expertise in this region. I would like to take this opportunity to acknowledge their important contributions in the past year.

Yogeshwar Sharma

Chief Executive

15 March 2011

Review of Operations

Hardy's operations in 2010 are highlighted with the continued success of its exploration programme, on the D3 block in the Krishna Godavari Basin, and, in the Company's role as operator, the extensive efforts taken to advance planning, and obtain approvals, for the next phase of development on the oil producing asset PY-3.

2010 Performance

Production from the PY-3 field in 2011 exceeded expectations after the resumption of production on 24 January 2010. Gross production averaged 3,156 barrels per day (bbld) during 2010, compared with the Company's forecast of 3,000 bbld. The Company had targeted securing the necessary technical and budgetary approvals from partners in early 2010 in order to coordinate the drilling of two further producing wells (Phase III) in the PY-3 field at the beginning of 2011. Throughout 2010 the Company worked closely with all stakeholders to advance the process. Due to minimum time required for planning, preceding budgetary approval, and limited marine weather window, drilling is now planned to commence in the early part of 2012.

At the beginning of 2010 the Company had planned the drilling of up to four exploration wells in the Krishna Godavari Basin. In July 2010, the Government of India granted a three year drilling moratorium on all deepwater blocks including D3 and D9 to the end of 2010 allowing additional time for the joint venture to complete its minimum work programme. The Company subsequently participated in the drilling of two exploration wells and was delighted to announce the fourth consecutive natural gas discovery (Dhirubhai 52) on the Company's D3 exploration block in the Krishna Godavari Basin. The well encountered a gross gas pay zone of 37.5 m in Pliocene aged sands. The second exploration well on the D9 exploration block recorded gas shows while drilling and proved the existence of reservoir quality sands and a biogenic gas petroleum system in this frontier, deep water block, but MDT testing indicated high water saturation. The cost of this well, which was plugged and abandoned following MDT testing, was well below budget.

Appraisal of the earlier discoveries on the D3 (Dhirubhai 39 and 41) and GS-01 (Dhirubhai 33) exploration blocks was planned for 2010. Hardy was pleased to confirm the submission of declaration of commerciality proposals, for the two blocks, to the GOI.

Through 2010 the Company continued to participate in a formal dispute resolution process to extend the expiry date of the CY-OS/2 licence. The process is expected to continue through 2011.

In the last quarter of 2010, the Company completed the sale of Hardy Oil (Africa) Limited realising gross proceeds of $4.6 million. The transaction is consistent with Hardy's stated objective to concentrate on evaluating the Company's exploration interests and optimising its producing asset in India.

The table below provides a brief comparison of our stated operational objectives for 2010 and our subsequent accomplishments through the year:

2011 has commenced with a flurry of activity, and the Company is looking forward to the positive contribution BP, our new partner, will have on the exploration programmes on our assets in the Krishna Godavari Basin.

Outlook for 2011

PY-3 - Gross average daily production for January 2011 and February 2011 was 3,520 bbld and 3,512 bbld respectively. We anticipate that the PY-3 field will average gross daily production of approximately 3,100 bbld for 2011.

PY-3 - During 2011, Hardy will seek approval from its partners and the GOI to drill two further producing wells at PY-3 field in 2012, and upgrade the production facilities to include artificial lift to extend the field life.

KG Basin - As announced on 21 February 2011, BP is acquiring an interest in 23 blocks from Reliance in India. Following final approvals, BP will hold 30 per cent interest in the blocks which includes Hardy's D3 and D9 blocks in the offshore Krishna Godavari Basin and AS-ONN-2000/1 in the Assam onshore basin.

D3 - The most recent W1 natural gas discovery on D3 brings the total number to four. The block has a large portfolio of undrilled prospects in various stages of maturation. Four of the six commitment wells have now been drilled on the D3 exploration block. Several material undrilled prospects exist on this block and the timing of drilling the two remaining commitment wells is pending the 3D seismic PSDM processing in the 'Panhandle' area and regional integration and prioritization of prospects.

D3 - An application for commerciality of three of the discoveries was submitted to DGH during the first quarter of 2011, while an appraisal programme was submitted for the fourth discovery. The Krishna Godavari Basin is an emerging world-class petroleum province and, together with rapidly improving Indian gas pipeline infrastructure and high demand for gas, the prospects for the economic development of gas resources in this area are excellent.

D9 - Following the KG-D9-B3 exploration well result on D9 announced earlier this year, which was subsequently plugged and abandoned, Hardy is working with the operator to update plans for this extensive block. The joint venture has submitted a request for a 6 month extension to July 2011 for phase I and is likely to drill the third of a four well commitment within this time period.

GS-01 - Hardy expects to receive approval of commerciality in respect of the application made for the West Coast offshore, GS-01 Dhirubhai 33 natural gas discovery, in the near future.

Competent Person's Report Update

The Company is commissioning the updating of a competent person's report (CPR) on an annual basis in conjunction with the year-end financial reporting process.

The 2011 Competent Persons Report has been undertaken by Gaffney, Cline & Associates Ltd (GCA). The report highlights the significant prospective resource potential of the Company's Krishna Godavari Basin assets.

Set out below is a summary of the key highlights of the reports.

Note: * Aggregated risked Prospective Resources have been derived by Hardy and are not aggregated or provided as risked volumes by GCA.

A detailed summary of the report is provided at the end of this announcement and the complete report can be downloaded from Hardy's website www.hardyoil.com.

Asset Review

The Company's operations in India are conducted through its wholly-owned subsidiary Hardy Exploration & Production (India) Inc. (HEPI).

Block KG-DWN-2003/1 (D3): Exploration

(Hardy 10 per cent interest)

2010 Operations

The Company's D3 block provided the highlight of Hardy's exploration programme with the drilling and testing of the fourth successive discovery of gas on the Company's D3 block (Dhirubhai 52). The primary results of operations undertaken on this block in 2010 are listed below:

KGV-D3-W1: On 31 August 2010, the Company announced a fourth discovery on the D3 block (Dhirubhai 52). The well KGV-D3-W1, was drilled in a water depth of 1,653 m to a total measured depth of 3,501 m. A gross gas pay zone of 37.5 m was encountered in Pliocene aged sands. The potential of the pay was evaluated by wire-line based modular pressure testing tool and collection of gas samples. Following post drill data analyses and integration with regional data, the KGV-D3-W1 gas accumulation was included with the Dhirubhai 39 and 41 gas discoveries as part of the Declaration of Commerciality (DOC) submission.

Additional interpretation and processing of the block wide 3D seismic surveys was continued on previously acquired data, including PSTM and AVO/inversion studies.

2011 Outlook

Exploration: The joint venture is planning for the drilling of at least one additional exploration well by the fourth quarter of 2011 following PSDM processing of the 'Panhandle' area 3D seismic and integration with the area geologic model. Current exploration analyses involve the multi-play evaluation and prospect ranking/risking in the prospect rich block. The drilling of the remaining two exploration wells will meet the block's phase one minimum work programme commitments.

DOC of Dhirubhai 39 and 41: In February 2011, the D3 joint venture Operating Committee reviewed and approved for Governmental submittal, a Commerciality Report of the Dhirubhai 39 and 41 gas discoveries in conjunction with the recently drilled Dhirubhai 52 discovery. The proposed development is a dry gas, subsea cluster development with the flexibility to add in additional zones and future area discoveries. It is anticipated that MC approval of the document will occur in 2011 following government review. This will in turn lead to preparation of a detailed Field Development Plan for the discoveries.

Appraisal of Dhirubhai 44: In February 2011, the D3 joint venture Operating Committee reviewed and approved an appraisal programme for the evaluation of the Dhirubhai 44 gas discovery (KGV-D3-R1). The appraisal programme provides for the undertaking of various geological, geophysical and development concept studies.

Background

The D3 block is situated in the emerging world class Krishna Godavari Basin in India, encompasses an area of 3,288 km2, is in water depths ranging from 400 m to 2,200 m, and is located approximately 45 km offshore. The block is operated by Reliance with BP as a newly farmed-in 30 per cent partner.

The minimum work programme for phase one of the licence requires the drilling of six exploration wells. To date, four exploration wells have been drilled and one well has been pre-drilled. The block encompasses several different play types ranging from shallow Pleistocene, stratigraphically trapped biogenic gas sands to toe thrust related Miocene structural traps with mixed biogenic and thermogenic sourcing.

Block KG-DWN-2001/1 (D9): Exploration

(Hardy 10 per cent interest)

2010 Operations

2010 saw the continuation of the drilling and geotechnical evaluation of the block's exploration programme. There are three play types postulated to be present in the block: structural (anticlines- northern, central and southern) strati-structural; and stratigraphic. The D9 joint venture has initially focused exploration efforts in the North West corner of the block covering an area of approximately 3,640 km2.

KG-D9-B3: On 5 January 2011, the Company announced the plugging and abandonment with gas shows of the second exploration well on the D9 block. The well KG-D9-B3, was drilled in a water depth of 2,948 m to a total measured depth of 3,829 m. The nearest well control is 47 km distant. The well encountered two Tertiary aged reservoir quality sand packages of gross thickness 70 and 40 meters each, with gas shows ranging from 6 per cent to 9 per cent recorded while drilling. Testing was carried out with the MDT tool which indicated high water saturation in the sand packages.

2011 Outlook

Exploration: Although the KG-D9-B3 well results were disappointing, the presence of thick reservoir quality sands and the presence of a petroleum system are encouraging for further exploration efforts. The cost of this well, which was plugged and abandoned following MDT testing, was well below budget.

The joint venture is planning for the drilling of at least one additional exploration well during 2011 following geologic and geophysical analysis of the KG-D9-B3 well and integration with the area geologic model. The drilling of the remaining two exploration wells will meet the block's phase one minimum work programme commitments.

Background

The licence encompasses 11,605 km2 in the Bay of Bengal where water depths vary from 2,300 m to 3,100 m. The block is operated by Reliance with BP as a newly farmed-in 30 per cent partner.

The joint venture has acquired over 4,188 km2 of 3D seismic data. Regarding the status of the D9 block, the operator has been granted a drilling moratorium for three years from January 2008 to December 2011 on the basis that the Operator has not been able to complete the minimum work obligations of exploratory drilling in view of non-availability of suitable deep water rigs in the international market. Similar proposals were also submitted by other operators including the national oil company ONGC.

Block GS-OSN-2000/1 (GS-01): Appraisal

(Hardy 10 per cent interest)

2010 Operations

The GS-01 joint venture concluded various geological and geophysical studies in relation to the appraisal of the GS01-B1 gas and condensate discovery (Dhirubhai 33), culminating in the submittal of a proposal for declaration of commerciality.

2011 Outlook

Hardy expects to receive approval of commerciality in respect of the application made for the GS-01 Dhirubhai 33 natural gas discovery in the near future.

Background

The GS-01 exploration licence is located in the Gujarat-Saurashtra offshore basin off the west coast of India, North West of the prolific Bombay High oil field. The original licence encompassed 8,841 km2 (5,890 km2 post relinquishment) and water depths vary between 80 m and 150 m.

The joint venture has previously acquired 2,216 km2 of 3D seismic data. As announced on 15 May 2007, the Dhirubhai 33 discovery (GS01-B1) flow-tested at a rate of 18.6 mmscfd gas with 415 bbld of condensate through a 56/64" choke at flowing tubing head pressure of 1,346 psi. Upon completion of phase one of the exploration programme the joint venture elected not to proceed to the second phase of exploration.

Block AS-ONN-2000/1 (Assam): Exploration

(Hardy 10 per cent interest)

2010 Operations

In 2010 the Company processed and interpreted the newly acquired 390 line km of 2D data. The exploration block's phase one minimum work programme has now been completed. Two material structural prospects have been mapped in the block from the new seismic data and are now under additional G & G evaluation for possible drilling. A request for a six month extension of phase one was submitted to the GOI in the fourth quarter of 2010, which is under consideration.

2011 Outlook

Subject to verification of the extension request noted above the, Assam joint venture will take a decision to enter into phase two of the exploration programme. The phase two work commitment consists of the drilling of one well within a two years.

Background

The AS-ONN-2000/1 exploration licence is located onshore in the north eastern state of Assam, India and north of the Brahmaputra River. The block is operated by Reliance with BP as a newly farmed-in 30 per cent partner. The exploration licence covers an area of 5,754 km2 and falls within the districts of Darrang and Sonitpur. The block is in phase one of a three phase exploration licence. Phase one (three years) expired in January 2011.

The topography of the area is primarily a plain of low relief and there is a reasonably established road network across the block. A national highway runs parallel to the Brahmaputra River and passes through the block. Different play types expected are structural (anticlinal and fault closures), stratigraphic (pinchout/wedgeout) within Palaeocene-Eocene and Gondwana packages and unconventional fractured/weathered basement.

Block CY-OS 90/1 (PY-3): Producing Oil Field

(Hardy 18 per cent interest - Operator)

2010 Production

Gross average daily field production for the year ended 31 December 2010 was 3,156 bbld (2009: 1,535 bbld; 2008: 2,550 bbld). The production facilities' uptime performance was 93 per cent (2009: 51 per cent). The increase in production was the result of a return to full production in late January following the extended shut down during 2009 and the positive effect of water injection based reservoir pressure support. The field recommenced production on 24 January 2010.

In 2010, the joint venture further extended the contract of the PY-3 field's production facility to 23 April 2011 under same terms and conditions. Negotiation for a long term facility contract with upgraded facilities is ongoing as part of a combined field redevelopment plan which is under evaluation.

Gross average daily production for January 2011 and February 2011 was 3,520 bbld and 3,512 bbld respectively. We anticipate that the PY-3 field will average gross daily production of approximately 3,100 bbld for 2011.

2010 Operations

Hardy has revised its geological and reservoir simulation models to incorporate new data gathered from the PY3-PD4-RL well which was drilled in 2009 and additional 3D seismic processing and interpretation. PSDM (pre-stack depth migration) and seismic facies analysis (Stratamagic) processing of the previously acquired 3D seismic survey was completed and integrated into new reservoir models. The revised models are the basis for the planned drilling and production facility programs.

2011 Outlook

The Company expects gross daily production of the PY-3 field to average 3,100 bbld in 2011. The PY-3 field joint venture's Technical and Operating Committees have recommended the drilling of two additional wells and facility upgrades including gas compression for gas lift and sales gas. Drilling of these wells is expected to commence in 2012, following the 2011 Monsoon (September - December). Commencement of drilling is subject to securing unanimous budget approval from the joint venture partners.

Background

The PY-3 field is located off the east coast of India 80 km south of Pondicherry in water depths between 40 m and 450 m. The Cauvery Basin was developed in the late Jurassic/early Cretaceous period and straddles the present-day east coast of India. The licence, which covers 81 km2, produces high quality light crude oil (49° API).

The field was developed using floating production facilities and subsea wellheads, a first for an offshore field in India. The facility at PY-3 consists of the floating production unit, 'Tahara', and a 65,000 DWT tanker, 'Endeavour', 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.

Liquid processing capacity on Tahara is 20,000 bbld with 17 mmscfd of gas handling capacity. The field currently produces associated gas in the range of 3.5 mmscfd. This produced gas is used as fuel gas with excess gas being flared. The stabilised crude oil is pumped from Tahara to Endeavour for storage and offloading to shuttle tankers. Crude oil from the PY-3 field is sold to CPCL at its refinery in Nagapattinam, approximately 70 km south of the PY-3 field.

Block CY-OS/2: Exploration

(Hardy 75 per cent interest - Operator)

2010 Operations

The formal dispute resolution process to extend the expiry date of this licence is progressing.

2011 Outlook

Following confirmation of the extension period, through the dispute resolution process, Hardy will undertake the activities necessary to fully appraise the Ganesha discovery. It is unlikely that an appraisal well will be drilled in 2011.

Background

Licence block CY-OS/2 is located in the northern part of the Cauvery Basin immediately offshore from Pondicherry and covers approximately 859 km2. The CY-OS/2 licence comprises two retained areas. The northern area includes the Fan A-1 discovery and the southern area lies immediately adjacent to the HEPI operated PY-3 field. The PY-1 gas field, a separate ring-fenced licence, lies within the southern part of the acreage and commenced production in the third quarter of 2010.

Ganesha: On 8 January 2007, the Company announced that the Fan A-1 exploration well had discovered hydrocarbons. In August 2007, the Company announced that it would proceed to the appraisal phase of the Ganesha non-associated gas discovery to establish potential commerciality.

Financial Review

During 2010, the Company enjoyed an increase in revenue, resulting from higher production (72%) and higher crude oil prices (54%). This has resulted in an increase in gross profit, the recording of operating profit (compared with a loss for 2009) and a profitable year. As well, the Company generated cash flow from continuing operations (before non cash working capital changes) of $4.0 million compared with a deficiency of $3.6 million. In October 2010, the Company sold its wholly owned subsidiary, Hardy Oil (Africa) Limited (including its wholly owned subsidiary Hardy Oil Nigeria Limited) for net cash consideration of $4.3 million. In December 2010, the Company successfully placed 3.37 million Ordinary Shares for net proceeds of $9.5 million. As a result, Hardy completed the year with cash and short-term investments of approximately $36.5 million and no long-term debt.

Key Performance Indicators

*Before changes in non cash working capital, tax paid, interest and investment income and finance costs

Operating Results

Production, Sales and Revenue

The Company operates the PY-3 field in the Cauvery Basin with an 18 per cent participating interest. Gross average daily field production for the year ended 31 December 2010 amounted to 3,156 stbd compared with 1,535 stbd for 2009. The increase is due to the resumption of production from the PY-3 field on 24 January 2010 whereas there was unplanned six month shut-in of the field to undertake repair of the offshore facilities in 2009.

Revenue from oil sales (after profit oil) increased to $12.9 million in 2010 compared to $7.7 million in 2009. The average price realised per barrel increased significantly by 54 percent from $52.96 during 2009 to $81.71 in 2010. Average daily sales amounted to 525 stbd compared with 398 stbd. Hardy's share of profit oil to the Government of India ('GOI') amounted to $2.8 million in 2010. No profit oil was payable in 2009 as a result of unutilised capital cost recovery pool.

Cost of Sales

Cost of sales (production, depletion and decommissioning costs) for 2010 increased from $6.8 million in 2009 to $8.0 million in 2010 as a result of the PY-3 field being in production for more than eleven months in 2010 compared with six months in 2009. Average cost amounted to $40.23 per barrel in 2010 compared with $49.16 per barrel during 2009. Production cost per barrel was substantially reduced from $37.87 in 2009 to $25.66 in 2010.

Gross Profit

As a result, gross profit increased more than five-fold from $0.8 million in 2009 to $5.2 million in 2010. The substantial increase is principally the result of higher revenues from higher oil sales, a higher average crude oil price realized in 2010 as well as a reduction in production cost per barrel.

Administrative Expenses

Administrative expenses decreased substantially from $8.3 million in 2009 to $3.3 million in 2010. The decrease is principally the result of a share based credit of $0.9 million recorded in 2010 compared with a charge of $2.8 million in 2009. As well, during 2009, additional costs associated with the drilling of PY3-PD4-RL well in early 2009 of $1.0 million were recorded of which $0.5 million was recovered in 2010.

Operating Profit

During October 2010, the Company divested of its operations in Nigeria. As a result, the Nigerian operations have been reported in the 2010 financial statements as discontinued operations.

The Company is reporting an operating profit from continuing operations of $1.9 million in 2010 compared with an operating loss of $7.5 million in 2009.

Interest and Investment Income

Investment and other income in 2010 amounted to $0.4 million compared with $0.3 million in 2009 as a result of higher average cash balances during 2010.

Finance Costs

Finance costs principally include the cost of providing bank guarantees to the GOI required by the provisions of production sharing contracts.

Profit before Taxation

The Company has recorded a profit before taxation from continuing operations of $2.2 million compared to a loss before taxation of $7.4 million in 2009. This results principally from higher revenues and a lower per barrel production cost, offset by lower general and administrative expenses.

Taxation

The Company has recorded a tax credit of $1.8 million during 2010 compared to a tax credit of $1.4 million in 2009. This arises principally as a result the crystallization of loss with respect to an inter company loan from the Company to Hardy Oil (Africa) Limited of $3.7 million, Minimum Alternate Tax offset having regard to a ten year carry forward period, and the non taxability of certain share based payments.

Net Profit from Continuing Operations

As a result, the Company recorded profit for the year from continuing operations of $4.0 million compared to a loss of $5.9 million for 2009.

Discontinued Operations

Effective 30 September 2010, the Company sold its Nigerian operations for net cash consideration of $4.3 million which approximated the net book value of underlying assets resulting in no gain or loss on the transaction. Overhead and depreciation expense was recorded amounting to $0.8 million and was recorded for the period to the end of September 2010.

Total Comprehensive Income

As a result, the Company recorded total comprehensive income of $3.2 million compared to a loss of $6.5 million in 2009.

Cash Flow from Operating Activities

During 2010, the Company generated cash flow from continuing operations activities, before changes in non-cash working capital, amounting to $4.0 million. This compares with cash used in operating activities, before changes in working capital, of $3.6 million in 2009. The positive cash flow results principally from higher oil sales (resulting from more than eleven months of production in 2010 compared with six months in 2009) and higher oil prices, as well as lower general administrative expenses. After non-cash working capital changes, cash used in continuing operating activities amounted to $0.9 million in 2010, compared to $0.4 million in 2009 resulting from increase in accounts receivable and a decrease in accounts payable at the end of 2010.

Cash used in discontinued operations (Nigeria) amounted to $0.7 million in 2010 compared with $0.6 million in 2009 and principally represents ongoing overhead in connection with Nigerian operations.

Capital Expenditure

Capital expenditure amounted to $6.1 million during 2010, compared to $13.6 million incurred during 2009. Capital expenditures amounting to $3.4 million and $2.5 million were incurred on the D3 and D9 blocks respectively principally on the drilling of exploration wells.

Sale of Hardy Oil (Africa) Limited

During October 2010, the Company sold its entire investment in Hardy Oil (Africa) Limited for a net cash consideration of $4.3 million. As a result of this divestment, the Company no longer has any operations in Nigeria. All of its operating assets at the end of 2010 are in India.

Site Restoration Deposit

This represents the deposit for site restoration for future site restoration expenses for the PY-3 field. In 2010, the Company increased the site restoration deposit by $0.5 million compared with $0.4 million in 2009. 

Financing Activities

During December 2010, the Company completed a placing of 3,370,000 Ordinary Shares at a price of £2.01 per share for net cash consideration of $9.5 million. During April 2009, the Company completed a placing of 6,208,997 Ordinary Shares at a price of £1.74 per share resulting in net proceeds from the equity issue of $15.2 million. In addition, the Company received investment income on its surplus cash resources amounting to $0.4 million.

Cash and Short-term Investments

The Company's cash and short-term investments increased by $5.9 million to $36.5 million at the end of 2010. The Company's net proceeds from financing ($9.5 million) coupled with net proceeds from the sale of its Nigerian operations ($4.3 million) exceeded its capital expenditure requirements and funds required for operations resulting in a $5.9 million increase in cash resources. The Company does not have any long-term debt.

Summary Statement of Financial Position

Hardy's non-current assets have essentially remained at $148.7 million. Current assets represent the Group's cash and short-term investments, trade and other receivables and inventory and have increased from $36.8 million to $43.6 million. At the end of 2010, of the $43.6 million of current assets, $36.5 million are represented by cash and short-term investments.

Current liabilities are principally trade and other accounts payable. The level of current liabilities is $13.4 million at the end of 2010 compared with $15.4 million at the end of 2009,

During 2010, the Company issued $9.5 million of equity and recorded a profit of $3.2 million. Consequently, the Company's net assets increased from $155.5 million at the end of 2009 to $167.3 million at the end of 2010.

Liquidity and Capital Resources

The Company has successfully raised financing in the past to provide funding for its ongoing exploration and development programmes and to augment its working capital. Having regard to Hardy's existing working capital position and its ability to raise potential financing, the directors are of the opinion that the Company has adequate resources to enable it to undertake its planned work programme of exploration, appraisal and development activities over the next 12 months. At the end of 2010, the Group has cash resources of $36.5 million and had no long term debt.

Dividends 

The Company has limited internally generated cash flows and has a planned capital expenditure programme. In the circumstances, the directors have chosen to reinvest cash flows and do not recommend the payment of a dividend in the foreseeable future.

Risk Factors

Hardy is in the international upstream oil and gas business which faces a variety of strategic, operational, financial and external risks. Under these distinct classes, the Company has identified certain risks pertinent to its business including: exploration and reserve risks; loss of key human resources; drilling and operating risks; security risk in area of operations, costs and availability of materials and services; economic and sovereign risks, market risk, foreign currency risk, loss of or changes to production sharing or concession agreements, joint venture or related agreements; and volatility of future oil and gas prices.

Effective risk management is critical to achieving our strategic objectives and protecting our assets, personnel and reputation. Hardy manages its risks through compliance with the terms of its agreements and application of appropriate policies and procedures, and through the recruitment and retention of skilled individuals throughout the organisation. Further, the Company has focused its activities mainly in known hydrocarbon basins in jurisdictions that have previously established long-term oil and gas ventures with foreign oil and gas companies, existing infrastructure of services and oil and gas transportation facilities, and reasonable proximity to markets.

A summary of the principal risks and uncertainties facing the Company and the way in which these risks are mitigated is provided under: 'Risks and Uncertainties' section of this report.

Key Financial Risks

In addition to the global financial risks described above, the Company is subject to the following specific 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 and United Kingdom., Therefore the Group is exposed to foreign exchange risk against Indian rupees and, UK sterling.

The Company has raised equity capital in the past and has received proceeds in UK sterling. The Company generally keeps funds in sterling to meet ongoing requirements for the foreseeable future. Any surplus sterling funds are converted into US dollars. Funds are converted into other currencies as and when required.

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, equity funds and debt financing. The Group further mitigates liquidity risk by seeking funds well in advance of requirements and 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 30 day average (14 day prior and 15 day after crude delivery) of Brent Crude less $0.35. The Board has no immediate intention to enter into fixed price 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.

Status of CY-OS/2 Discovery Block

The auditors have provided an emphasis of matter comment in their audit report with reference to the uncertainty concerning the Group's request for an extension of its exploration licence in block CY-OS/2 as disclosed in note 7 to the consolidated financial statements.

The Company's Chairman's Statement, Chief Executive Officer's Statement, Review of Operations, Financial Review, and Risks and Uncertainties have been prepared to substantially comply with the Accounting Standards Board Operating and Financial Review Reporting Statement issued in January 2006.

Dinesh Dattani

Finance Director

15 March 2011

Risks and Uncertainties

As an oil and gas exploration and production company with operations focused in India, Hardy is subject to a variety of risks and uncertainties. Managing risk effectively is a critical element of our corporate responsibility and underpins the safe delivery of our business plans and strategic objectives. It protects our reputation, supports our ability to do business and helps to create long-term competitive advantage. The Group has a systematic approach to risk identification and management which combines the Board's assessment of risk with risk factors originating from and identified by the Group's senior management team.

Clear responsibility - The Board is responsible for the overall group strategy, acquisition and divestment policy, approval of major capital expenditure projects, corporate costs, significant financing matters and the management of risk. The Board recognises that risk is inherent across Hardy's operations, and all activities are subject to an appropriate review to ensure that risks are identified monitored and managed to the extent possible.

Identification and monitoring - The Board has adopted a framework for risk assessment and monitoring providing for four distinct categories; strategic, financial, operational, and compliance. The Board's review of the Company's risks and uncertainties involves a detailed description of each risk and an assessment of its perceived relevance and likelihood of materially impacting Hardy's business. Risks that are identified as high and or trending upwards are noted and assigned to the Executive Directors to monitor and if possible pro-actively mitigated. The Board is provided regular updates of the identified principal risks at scheduled Board meetings.

The underlying risks and uncertainties inherent with Hardy's current business model are summarised below;

Strategy risk - The Group's strategy is predominantly driven by the exploration, appraisal, development and production of its existing assets in India. There are risks inherent in the exploration, appraisal, development and production of oil and gas reserves and resources. The Group's strategy includes acquiring additional oil and gas properties principally in India. 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 secure the financing necessary to complete such future acquisitions.

Financial risk - Any volatility and future decreases in crude oil prices could materially and adversely affect the Group's business, prospects, financial condition and results of operations. Other major financial risks facing the Company are; failure to receive extensions for expiring exploration and production contracts; inability to access debt and/or equity financing for further exploration and development, cost inflation or overruns associated with exploration, appraisal and development activities, and overall deterioration of shareholder sentiment. Additional discussion of financial risks is provided for in the Financial Review section.

Operations risk - Exploration and production activities by their nature involve significant risks. Risks such as delays in executing work programmes as a result of access to drilling rigs, 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.

Compliance risk - The Group's current business is dependent on the continuing enforceability of the PSCs, farm-in agreements and exploration and development licences. The Group's core operational activities are dependent on securing various governmental approvals. Developments in politics, laws, regulations and, or general adverse public sentiment could compromise securing such approvals in the future.

Principal risks for 2010

Throughout the year, Hardy's senior management and Board have critically reviewed and evaluated the risks facing the Group. As a result of this process, the Board has synthesised these risks in this year's report by defining the principle risks and uncertainties for 2010 and establishing clear policies and responsibilities to mitigation their possible negative impact to the business a summary of which is provided below;

Emphasis of matter - The board notes that the auditors have provided an emphasis of matter comment in their audit report with reference to the uncertainty concerning the Group's request for an extension of its exploration licence in block CY-OS/2. In 2010, the Group formally commenced arbitration proceedings pursuant to dispute resolution provisions of the governing PSC.

The Group holds a 75 per cent participating interest in the block CY-OS/2 which is offshore on the south east coast of India. Intangible assets include an amount of $83,530,141 with respect to exploration expenditures on the block wherein a gas discovery was announced on 8 January 2007. The exploration period for the block ended on 23 March 2007 and the GOI has been requested to extend the block for appraisal and declaration of commerciality for its gas discovery until 7 January 2012.

Provisions of the PSC provide for an appraisal period of 60 months from the date of discovery. For an oil discovery, this period is limited to 24 months. DGH has informed HEPI that in their opinion the discovery is classified as an oil discovery and not a NANG discovery.

The Company has obtained third party legal and technical opinions that support the Company's view that the discovery is NANG and have referred the dispute to arbitration for adjudication. The Group believes that it will be successful in obtaining the extension of its licence in the arbitration.

In the event that HEPI's application for an extension of the CY-OS/2 licence was to be unsuccessful, the capitalised expenditure will be subject to impairment testing.

HARDY OIL AND GAS plc

Consolidated Statement of Comprehensive Income 

For the year ended 31 December 2010

HARDY OIL AND GAS plc

Consolidated Statement of Changes in Equity 

For the year ended 31 December 2010

HARDY OIL AND GAS plc

Consolidated Statement of Financial Position 

As at 31 December 2010

HARDY OIL AND GAS plc

Consolidated Statement of Cash Flows

For the year ended 31 December 2010

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

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 measurement

Hardy prepares its financial statements on a historical cost basis except as otherwise stated.

b) Going concern

The Group has a history of profitable operations and has successfully raised financing in the past to provide funding for its ongoing exploration and development programs and to augment its working capital. Having considered the guidance given in the document "Going concern and liquidity risk: Guidance for Directors" issued in October 2009 by the Financial Reporting Council and having regard to the Group's existing working capital position and its ability to raise potential financing, if required, the Directors are of the opinion that the Group has adequate resources to enable it to undertake its planned work program of exploration, appraisal and development activities over the next twelve months.

c) Basis of preparation

Hardy prepares its financial statements in accordance with applicable International Financial Reporting Standards (IFRS) and interpretations issued by the International Accounting Standards Board as adopted by the European Union.

As at the date of approval of these financial statements, the following standards and interpretations were in issue but not yet effective:

IFRS 9 Financial instruments

IAS 24 Related Party Disclosures (Revised 2009)

Amendment to IAS 32Classification of rights issues

IFRIC 19 Extinguishing financial liabilities with equity instruments

IFRIC 14 (Amendment) Prepayments of a minimum funding requirement

Improvement to IFRS issued May 2010

Amendment to IFRS 7 Financial instrument: Disclosures

Amendment to IAS12 Income Taxes

The Directors do not anticipate that the adoption of these standards and interpretations in future reporting periods will have a material impact on the Group's results.

d) Functional and presentation currency

These financial statements are presented in US dollars which is the Group's functional currency. All financial information presented is rounded to the nearest US dollar.

e) Basis of consolidation

The consolidated financial statements include the results of Hardy Oil and Gas plc and its subsidiary undertakings. The consolidated statement of comprehensive income and the consolidated statement of cash flows include the results and cash flows of subsidiary undertakings up to the date of disposal.

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

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 and costs attributable to its participating interests under the proportional consolidation method.

f) 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 of India as part of profit sharing, 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.

g) 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 a geographical cost pool, which is not larger than the Indian segment.

The capitalized exploration and evaluation costs are classified as Intangible assets - exploration which includes 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 statement of comprehensive income 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 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.

ii) Oil and gas development and producing assets

Development and production assets are accumulated on a field by field basis. These comprise the cost of developing commercial reserves discovered to put 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.

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

iii) Decommissioning

At the end of the producing life of a field, costs are incurred in removing and decommissioning facilities, plugging and abandoning wells. Future decommissioning costs are estimated and stated at an amount representing the costs which would be incurred should decommissioning occur at the year end date and the estimates are reassessed each year. The provision is assessed at prices ruling at the year end date and, accordingly, it is not appropriate to discount this provision. The decommissioning asset is included within the property, plant and equipment with the cost of the related assets installed and is 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 statement of comprehensive income.

iv) Disposal of assets

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

h) 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 statement of comprehensive income. Impairment reviews on development / producing oil and gas assets for each field are carried out 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 representing 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, the excess amount is recognized in the statement of comprehensive income as impairment.

i) 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:

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

j) Intangible assets

Intangible assets other than oil and gas assets are measured at cost and depreciated over their expected useful economic lives as follows:

k) Investments

Investments by the parent company in its subsidiaries are stated at cost.

l) Short term investments

Short term investments are regarded as "financial assets at fair value through profit or loss" and are carried at fair value. In practice, the nature of these investments is such that the fair value equates to the value of initial outlay and therefore in normal circumstances no fair value gain or loss is recognized in the statement of comprehensive income.

m) Inventory

Inventory of crude oil is valued at the lower of average cost and net realisable value. Average cost is determined based on actual production cost for the year. Inventories of drilling stores are recorded at cost including taxes duties and freight. Provision is made for obsolete or defective items where appropriate based on technical evaluation.

n) Financial instruments

Financial assets and financial liabilities are recognized at fair value in the Group's statement of financial position based on the contractual provisions of the instrument.

Trade receivables are not interest bearing and their fair value is deemed to be their nominal value as reduced by necessary provisions for estimated irrecoverable amounts.

Trade payables are not interest bearing and their fair value is deemed to be their nominal value.

o) Equity

Equity instruments issued by Hardy and the Group are recorded at net proceeds after direct issue costs.

p) 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 statement of comprehensive income as it excludes certain items 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 year end date.

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

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.

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 year end 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 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 year end date .

q) Foreign currencies

Foreign currency transactions are accounted for at the exchange rate prevailing on the date of the transaction. At the year end date, all foreign currency monetary assets and monetary liabilities are restated at the closing rate. Exchange difference arising out of actual payments / realizations and from the year end restatement are reflected in the statement of comprehensive income.

Rates of exchanges are as follows:

r) Leasing commitments

Rental charges or charter hire charges payable under operating leases are charged to the statement of comprehensive income as part of production cost over the lease term.

s) 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. 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 management estimates and considers non-transferability, exercise restrictions and behavioural considerations.

2. Segment analysis

The Group is organized into two business units as at end of the year: India and United Kingdom. The India business unit is operated by the wholly owned subsidiary, Hardy Exploration & Production (India) Inc. In addition, Hardy Oil and Gas plc operates in the United Kingdom. A Nigeria business unit was operated by Hardy Oil Nigeria Limited, which was sold on 27 October 2010 with an effective date of 30 September 2010.

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

The India business unit focuses on exploration and production of oil and gas assets in India. The United Kingdom business unit is the holding company. Management monitors these business units separately for resource allocation, decision making and performance assessment.

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

The Group is engaged in one business activity, the production and exploration for oil and gas. Other income relates to technical services to third parties, overhead recovery from joint venture operations and miscellaneous receipts, if any. Revenue arises from the 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.

Hardy Oil (Africa) Limited ("HOAL") a wholly owned subsidiary of Hardy Oil and Gas plc, holding exploration assets through its subsidiary Hardy Oil Nigeria Limited was sold with effect from 30 September 2010. Accordingly, the loss relating to Nigerian operations is presented as loss on discontinued operations.

3. Cost of sales

Production costs included in the cost of sales consists of:

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

4. Reconciliation of operating profit (loss) of continuing operations to operating cash flows

5. Earnings (loss) per share

Earnings per share for continuing operations are calculated on a profit of US$4,032,336 for the year 2010 (loss for 2009: US$5,927,105) on a weighted average of 68,597,410 Ordinary Shares for the year 2010 (2009: 66,506,242).

The diluted earnings per share for continuing operations are calculated on a profit of US$4,032,336 for the year 2010 (loss for 2009: US$5,927,105) on a weighted average of 70,068,576 Ordinary Shares for the year 2010 (2009: 71,258,343). For the year 2009, the weighted average shares are calculated after giving impact to dilutive potential Ordinary Shares of 1,471,166 relating to share options after excluding 2,982,233 options wherein the strike price exceeds the average market price of the shares of the Company.

Comprehensive earnings per share are calculated on a profit of US$3,245,982 for the year 2010 (loss for 2009: US$6,517,176) on a weighted average of 68,597,410 Ordinary Shares for the year 2010 (2009: 66,506,242).

The diluted earnings per share on profit (loss) attributable to parent company are calculated on a profit of US$3,245,982 for the year 2010 (loss for 2009: US$6,517,176) on a weighted average of 70,068,576 Ordinary Shares for the year 2010 (2009: 71,258,343).

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

6. Property, plant and equipment

Oil and gas assets represent interests in producing oil and gas assets falling under the India cost pool. Other fixed assets consist of office furniture, computers, workstations and office equipment.

7. Intangible assets - exploration

The Group holds a 75 percent participating interest in the block CY-OS/2 off the east coast of India. Intangible assets include an amount of US$83,530,141 with respect to exploration expenditures on the block wherein where a gas discovery was announced on 8 January 2007. The exploration period for the block ended on 23 March 2007. The Government of India ("GOI") has been requested to extend the block for appraisal and declaration of commerciality for its gas discovery until 7 January 2012. The GOI have declined this request.

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

Provisions of the Production Sharing Contract ("PSC") provide for an appraisal period of 60 months from the date of discovery. For an oil discovery, this period is limited to 24 months. The Company has obtained third party legal and technical opinions that support the Company's view that the discovery is NANG. Accordingly, the dispute has been referred to arbitration for adjudication. The arbitration process is continuing at the date of approval of these financial statements.

In the event that Hardy's application for an extension of the CY-OS/2 licence was to be unsuccessful, the capitalized expenditure will be subject to impairment testing.

Hardy Oil (Africa) Limited (HOAL) was sold on 27 October 2010 with an effective date of 30 September 2010. Therefore the exploration expenditure relating to the Nigeria cost pool is deleted.

8. Intangible assets - others

Intangible assets - others represent the cost of software used for geological and geophysical studies and other software for normal business operations.

9. Disposal of undertaking

The entire share capital of HOAL, a holding company of Hardy Oil Nigeria Limited, which had exploration assets in the blocks Oza and Atala, was sold for a net consideration of US$4,275,047 (net of expenses) on 27 October 2010 with an effective date of 30 September 2010.

The net book value of the assets of HOAL as at 30 September 2010 was US$4,275,047 and therefore no loss or gain is recognized on disposal.

10. Members of the Group

The Group comprises the parent company - Hardy Oil and Gas plc - and the wholly owned subsidiary Hardy Exploration & Production (India) Inc which is incorporated under the Laws of State of Delaware, United States of America. The members of the Group are engaged in the business of exploration and production of oil and gas and all are included in the consolidated financial statements.

HARDY OIL AND GAS plc

Selected Notes to the Consolidated Financial Statements

For the year ended 31 December 2010

11. Short term investments

The above investments are in liquid funds which can be converted into cash at short notice. Book value of these investments approximates fair values.

12. Share capital

Ordinary Shares issued in the years 2010 and 2009 were as a result of placings in December 2010 and April 2009 respectively. Ordinary Shares issued have equal voting and other rights with no guarantee to dividend or other payments.

2010 Reserves and Resources

Provided below are summary and comparison tables for Hardy's reserve and resources as at 31 December 2010. In 2010 the Company disposed of Hardy Oil (Africa) Limited, which held interest in the Oza and Atala licences via Hardy Oil Nigeria Limited. The reserves and resources associated with those assets are not provided for in the tables below (Oza - reserves 0.41 mmbbl, contingent resources 1.2 mmbbl; Atala contingent resources 43.5 bcf, 1.3 mmbbl).

Reserves (Proven Plus Probable)

Net PY-3 oil production from the date of the previous report (31 December 2009) to the effective date (31 December 2010) of GCA's report was 207 MBbl.

Notes:

1. The GCA has used the Petroleum Resources Management System published by the Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers in March 2007 (SPE PRMS) as the basis for its classification and categorisation of hydrocarbon volumes.

2. On 19 April 2007, the PY-3 joint venture management committee had approved gross expected ultimate 2P oil Reserves of 44.4 MMBbl. As of 31 December 2010 the field had produced 24.1 MMBbl giving 2P oil Reserves of 20.3 MMBbl, about 5 MM bbl higher than the 2P estimate by GCA.

3. The Company has filed the updated GCA Competent Persons Report (March 2011) with the Directorate General of Hydrocarbons, of the Ministry of Petroleum and Natural Gas, of the Government of India ('DGH').

4. Net entitlement reserves are reserves based on Hardy's entitlement of cost oil plus a share of profit oil.

Contingent Resources (2c)

Net 2C gas Contingent Resources have increased by 10 per cent to 16.2 BCF as a result of the W1 discovery on the D3 block.

Notes

1. GCA has used the Petroleum Resources Management System published by the Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers in March 2007 (SPE PRMS) as the basis for its classification and categorisation of hydrocarbon volumes.

2. With respect to Ganesha-1 (CY-OS/2) non-associated natural gas discovery, in 2010 the Group formally commenced arbitration proceedings pursuant to dispute resolution provisions of the governing PSC regarding a licence extension request.

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

Prospective Resources

D3 - Having drilled W1 prospect and mapped additional prospects/leads in 2010, the total number of identified prospects and leads has increased to 29 (December 2009: 26) with an average size of 233 BCF per prospect. PSDM processing in the 'Panhandle' area is on-going and updated mapping of the block is in progress.

D9 - The overall risked Prospective Resources of the D9 block remain substantial. The data gathered from the KG-D9-B3 well (encountering reservoir with gas shows) has led to a limited revision of the risking. The oil Prospective Resources in the Cretaceous and Palaeocene remain unchanged.

Notes:

1. Aggregated risked Prospective Resources have been derived by Hardy and are not aggregated or provided as risked volumes by GCA.

2. The GCA has used the Petroleum Resources Management System published by the Society of Petroleum Engineers, World Petroleum Council, American Association of Petroleum Geologists and Society of Petroleum Evaluation Engineers in March 2007 (SPE PRMS) as the basis for its classification and categorisation of hydrocarbon volumes.

3. With respect to Ganesha-1 (CY-OS/2) non-associated natural gas discovery, in 2010 the Group formally commenced arbitration proceedings pursuant to dispute resolution provisions of the governing PSC regarding a licence extension request.

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

Definitions and Glossary of Terms

Assam block: Licence AS-ONN-2000/1

bbl: barrel

bbld: barrel per day

Board: The Board of Directors of Hardy Oil and Gas plc

the Company: Hardy Oil and Gas plc

CPCL: Chennai Petroleum Company Limited, formerly known as Madras Refinery Limited

CPR: Competent persons report

D3: Licence KG-DWN-2003/1 awarded in NELP V

D9: Licence KG-DWN-2001/1 awarded in NELP III

DGH: Directorate General of Hydrocarbons

Dhirubhai 33: Gas discovery on GS-01-B1 well

Dhirubhai 39: Gas discovery on KGV-D3-A1 well

Dhirubhai 41: Gas discovery on KGV-D3-B1 well

Dhirubhai 44: Gas discovery on KGV-D3-R1 well

FDP: Field development plan

FSO: Floating storage and offloading vessel

GAIL: Gas Authority of India Limited

Ganesha: Gas discovery on Fan-A1 well located in CY-OS/2

GCA: Gaffney, Cline & Associates Ltd

Group: The Company and its subsidiaries

GS-01: Licence GS-OSN-2000/1 awarded under NELP II

H2: Second half of the year

Hardy: Hardy Oil and Gas plc

HEPI: Hardy Exploration & Production (India) Inc.

HOA: Hardy Oil (Africa) Limited

HOEC: Hindustan Oil Exploration Company Limited

HON: Hardy Oil Nigeria Limited

HSE: Health, safety and environment

IFRS: International Financial Reporting Standards

IPO: Initial public offering

KG Basin: Krishna Godavari sedimentary basin comprising an area on the south east India continental shelf

London Stock Exchange: London Stock Exchange plc

LTA: Lost time accident

Main Market: Official List of the London Stock Exchange's

market for listed securities

Management Committee: As per India PSCs the Management Committee comprises representatives of each participating interest holder, DGH and the Ministry of Petroleum and Natural Gas of India

NELP: New Exploration Licensing Policy of the Ministry of Petroleum and Natural Gas of India

Operating Committee: As per India PSCs the Operating Committee comprises representatives of the various participating interest holders in the licence

Ordinary Share: The Ordinary Share of US$ 0.01 each in the capital of the Company

PSC: Production sharing contract

PY-3: Licence CY-OS-90/1

Reliance: Reliance Industries Limited

UK: United Kingdom

US: United States of America

Glossary of terms:

$: United States dollars

2D/3D: Two dimensional/three dimensional

2P: Proven plus probable

API°: American Petroleum Institute gravity

AVO: Amplitude variations with offset

BOP: Blow-out preventer

bwpd: Barrels of water per day

Contingent Resources: Those quantities of petroleum estimates, 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

Prospective Resources: Those quantities of petroleum which are estimated, on a given date, to be potentially recoverable from undiscovered accumulations

DST: Drill stem test

km: Kilometre

km2: Kilometre squared

lkm: Line kilometre

m: Metre

MDT: Modular formation dynamics tester

mmcfd: Million standard cubic feet per day

mmcmd: Million standard cubic metres per day

mmbbl: Million stock tank barrels per day

PSDM: Pre-stack depth migration

psi: Pounds per square inch

scf: Standard cubic feet

scfd: Standard cubic feet per day

TCF: Trillion cubic feet

TVD: Total vertical depth

TVDRT: Total vertical depth from rotary table

NOTES TO THE EDITORS

Hardy Oil and Gas plc is an upstream oil and gas company focused in India. Its portfolio includes a blend of exploration, appraisal, and production assets. Hardy's goal is to evaluate and exploit its asset base with a view to creating significant value for its shareholders.

Hardy Oil and Gas plc has existing production from an offshore field in India's Cauvery basin. Hardy also has interests in four offshore exploration blocks in India's Saurashtra, Cauvery, and Krishna Godavari basins, and one onshore exploration block in the Assam Basin.

Hardy is incorporated under the laws of the Isle of Man and headquartered in London, UK. Ordinary shares of Hardy were admitted to the Official List and the London Stock Exchange's market for listed securities effective 20 February 2008 under the symbol HDY.

The Company's Indian assets are held through the wholly owned subsidiary Hardy Exploration & Production (India) Inc, located in Chennai, India.

For further information please refer to our website at www.hardyoil.com