HDY.L Regulatory News (HDY)

 Immediate release 24 August 2011

Hardy Oil and Gas plc

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

Interim Results for Six Months ended 30 June 2011

Hardy Oil and Gas plc (LSE: HDY), the oil and gas exploration and production company focused in India, is pleased to report its Interim Results for the six months ended 30 June 2011.

All financial amounts are stated in US dollars unless otherwise indicated.

Operational Highlights

·; PY-3: In the first half of 2011, participating interest daily production averaged 615 bbld (H1 2010: 532 bbld) (gross: 3,417 bbld, H1 2010: 2,953 bbld). Average gross daily production for the month of July 2011 was 3,112 bbld

·; PY-3: The PY-3 field has been temporarily shut-in from 30 July 2011 pending approval to award a long term contract for the lease of the FPS currently utilised in the field

·; D9: On 22 June 2011 the Company announced the block's first natural gas discovery in the KG-D9-A2 exploration well (Dhirubhai 54). Three gas bearing sand reservoirs with a gross thickness of approximately 22 m were encountered and evaluated by wireline MDT

·; D3: A proposal for the declaration of commerciality for the Dhirubhai 39, 41 and 52 natural gas discoveries was submitted

Financial Highlights

·; Revenue increased by 35 per cent to $7.4 million (H1 2010: $5.5 million)

·; Cash flow from continuing operations (before changes in non-cash working capital) increased to $2.5 million (H1 2010: $0.7 million)

·; Profit from continuing operations amounted to $0.4 million (H1 2010: loss of $0.9 million)

·; Capital expenditures amounted to $4.2 million, principally on the drilling of the KG-D9-A2 exploration well

·; Cash and short term investments at 30 June 2011 amounted to $37.1 million; the Company has no long term debt

Corporate

·; D3: The Company elected not to exercise an option to acquire an additional three per cent participating interest in the D3 block for $150 million

·; As announced on 31 May 2011, the Company's executive director Dinesh Dattani will step-down from his role as Finance Director effective 31 August 2011

·; BP and Reliance received GOI approval to proceed with BP's farm-in to 21 blocks in India, including the D3 and D9 exploration blocks in which Hardy has an interest

Outlook

·; D9: Drill one exploration well by the end of 2011, completing the minimum work commitment on the D9 exploration licence

·; D3: Drill one exploration well by the end of the first half of 2012

·; GS-01: Approval of commerciality for the GS-01 Dhirubhai 33 natural gas discovery is expected in the near future

·; PY-3: Recommencement of production pending receipt of necessary approvals

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

"We are pleased with the continuing developments on our Krishna Godavari Basin assets. The first natural gas discovery on the D9 block, the submission of a declaration of commerciality proposal for the D3 discoveries, and BP's farm-in highlight the potential of our exploration assets. We are working closely with all stakeholders to secure the necessary approvals to resume production from the PY-3 field as soon as possible. Hardy has over $37 million in cash and short term investments which is sufficient to meet our exploration commitments through 2012."

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CHAIRMAN'S STATEMENT

Overview

The Company continued the positive momentum generated in 2010 with encouraging developments in the first half of 2011. Hardy realised a marked improvement in its financial performance as a result of higher oil prices and improved production performance. We also announced the first discovery on our D9 exploration licence in the Krishna Godavari Basin, and welcomed the global E&P leader, BP, into several of our India based joint ventures.

Strategy

We have a clear objective to create significant shareholder value through an India focused, upstream oil and gas exploration and development strategy. India offers attractive upstream oil and gas opportunities through its underexplored sedimentary basins, a globally competitive fiscal regime, and a robust economy with growing energy requirements. We believe that the Company has a sustainable platform to continue to participate in the Indian energy growth story. The addition of further short to medium term production would enhance our prospects and management continues to examine opportunities in pursuit of this goal.

Operations

The Company had an active start to the year with the results of two exploration wells announced on the D9 block, steady production from PY-3 and the submission of a declaration of commerciality (DOC) proposal for the D3 exploration block to the Government of India (GOI).

D9 gas discovery - On 22 June 2011, the Company announced the first discovery on the D9 block in the KG-D9-A2 well (Dhirubhai 54). Three gas bearing sand reservoirs with a gross thickness of approximately 22 m were encountered and evaluated by wireline MDT. We are encouraged by this discovery which extends the proven Miocene play fairway into the frontier D9 block. The discovery further enhances our understanding of the block's petroleum systems and reinforces our enthusiasm for unlocking its hydrocarbon potential. On 5 January 2011, the Company announced the plugging and abandonment of the second exploration well on the D9 block.

D3 DOC submission - Over the past four years the D3 block has produced four consecutive gas discoveries. In February 2011 the D3 joint venture submitted a declaration of commerciality proposal for three of the discoveries, taking us a step closer to our ultimate objective of realising the monetisation of our exploration efforts. We view the D3 exploration block with considerable optimism and believe that our existing exploration portfolio offers significant organic growth potential for the Company.

Production - For the six months ended 30 June 2011 the PY-3 oil field produced at an average rate of 3,417 bbld (net: 615 bbld) representing a 15.7 per cent increase compared to the same period in 2010. The PY-3 field was shut-in on 30 July 2011 pending the award of a contract for the lease of the field's floating production system (FPS) which awaits various approvals. Management is working diligently to secure the necessary approvals to resume production.

HSE award - The Company was delighted to be the recipient of the India Coast Guard's inaugural Environmental Awards 2010 for oil handling. We would like to commend our operations team in India for their commitment and professionalism in ensuring safe operations and being an active participant in developing best practices for India's offshore accident prevention and response activities.

Financial

The Company is reporting a significant improvement in its financial performance as a result of uninterrupted production from the PY-3 field and a robust oil price environment.

Revenue for the six months ended 30 June 2011 increased by 35.5 per cent to $7.4 million. The improvement in revenue is primarily attributed to the average oil price realised increasing by 38.9 per cent to $109.91 per bbl and a 44.7 per cent increase in oil sales to 98,075 bbl compared to the six months ended 30 June 2010. Profit oil paid to the GOI amounted to $3.5 million during the six months ended 30 June 2011 compared to nil for the corresponding period in 2010.

The Company generated cash flow from continuing operations (before changes in non-cash working capital) of $2.5 million in the first half of 2011 compared with cash flow of $0.7 million for the same period in 2010. All of the Company's production costs and cash administrative expenses were fully funded by crude oil sales revenues from the PY-3 field during the first half of 2011.

The Company recorded a net profit from continuing operations of $0.4 million compared to a net loss of $0.9 million in 2010. The Company's fully diluted profit per share was $0.01 in 2011 compared to fully diluted loss per share of $0.02 reported for the same period in 2010.

Total capital expenditures amounted to $4.2 million, incurred principally on the drilling of the natural gas discovery well KG-D9-A2.

Hardy's cash resources increased by $0.6 million since the year ended 31 December 2010 to $37.1 million at 30 June 2011; the Company has no long-term debt.

Emphasis of Matter

The auditors have provided an "emphasis of matter" comment in their independent review 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 2(i) of the consolidated financial statements.

Corporate

BP Farm-in - On 9 August 2011 Reliance announced that the GOI had approved the transfer of a 30 per cent participating interest in 21 exploration and production licences to BP. Prior to the GOI approval, Hardy had retained an option from Reliance to increase its participating interest in D3 by three per cent for a cash payment of approximately $150 million. The net consideration implied a gross value of approximately $5.0 billion for the D3 exploration licence ($500 million net to Hardy).

On 10 May 2011, the Company announced that, after due consideration of the Company's cash position and future capital requirements under the existing production sharing contracts, the Board had elected not to exercise the option. Hardy's participating interest in the D3 exploration licence remains at 10 per cent and we are delighted to welcome BP as a new partner in the D9 and D3 exploration licences.

Finance Director - On 31 May 2011 Hardy announced that the Company's Finance Director Mr Dinesh Dattani will be leaving the Company on 31 August 2011 to return to his permanent residence in Calgary, Canada. Mr. Dattani joined Hardy as Finance Director in July 2007. He led the process to transfer Hardy's listing from AIM to the main market of the London Stock Exchange, completed a number of successful equity financings and participated in the development and execution of corporate strategy.

We would like to thank Dinesh for his considerable contributions to Hardy over the past four years. His expertise and leadership have been instrumental in advancing a number of our strategic objectives. We will be sorry to see him go and wish him every success in the future.

Hardy has considerable financial reporting and taxation expertise in Chennai, India as well as business development, treasury and investor relations competencies in London, UK. Mr Dattani's responsibilities will be distributed between senior management personnel at these locations and the Board expects to release further details in due course.

Risk management

The Board has adopted a formal risk and uncertainties review process involving the 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 the second half of 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 and interpretation technologies have reduced this uncertainty, it cannot be eliminated.

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

·; Work programme - The Group's exploration plans comprise activities primarily on non-operated blocks. The timing of execution of activities may not commence as currently forecasted and significant delays may be experienced.

·; Production - The Company's sole source of revenue is from a single producing oil well in the PY-3 field. A prolonged shut-in would have an 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 would be required.

·; Timeliness of regulatory approval - Under the terms of the PSCs, major capital expenditure and annual operating budgets require the approval of the Management Committee, which includes joint venture partners and GOI representatives. Prolonged delays in securing such approvals would have a material impact on the monetisation of the Company's oil and gas reserves.

·; Loss of acreage - The Company's exploration licences are at or approaching the end of their initial exploration phases. The Company will be subject to relinquishment requirements, ranging from a portion of a block to an entire licence, at the end of the initial phase.

·; Key personnel - The Company's ability to compete in the upstream oil and gas exploration and production industry is dependent on being able to retain and attract experienced technical personnel.

Outlook

Set out below is our planned operating activity in the coming months;

Exploration:

·; D9 - We anticipate the drilling of the fourth exploration well and the submission of an appraisal plan for the KG-D9-A2 natural gas discovery prior to the end of 2011. The drilling of the fourth exploration well will complete the minimum work programme commitments for phase one of the exploration period.

·; D3 - We anticipate that the operator will initiate PSDM processing for the 3D seismic data covering the "pan handle" area of the D3 block. Exploration drilling is unlikely to recommence prior to the completion of this work. As a result we anticipate further drilling to commence in the first half of 2012.

Appraisal:

·; D3 - The joint venture submitted a proposal for the declaration of commerciality for the Dhirubhai 39, 41 and 52 natural gas discoveries. We anticipate that the GOI review of this proposal will continue through the remainder of 2011. An appraisal plan for the Dhirubhai 44 discovery was submitted in February 2011.

·; GS-01 - The joint venture is continuing discussions with the GOI regarding the proposal for commerciality submitted in May of 2010. We do not anticipate significant expenditures on the GS-01 block in 2011.

Development:

·; PY-3 - Operating Committee approval was obtained in April 2011 for the field's redevelopment plan which includes a two well drilling programme and the addition of artificial lift and gas export. We continue to work with all stakeholders to secure the necessary final approvals to award a long term contract for the field's FPS and the budget for the drilling of additional production wells. The timing of commencement of drilling and the installation of gas lift facilities are subject to the timing of receipt of necessary approvals.

Production:

·; PY-3 - The PY-3 field will remain shut-in until the necessary approvals are in place to award a contract for the existing FPS system. Once production resumes, we expect the field to continue to produce over 3,000 bbld for the remainder of 2011.

We are pleased with the continuing developments on our Krishna Godavari Basin assets. The first natural gas discovery on the D9 block, the submission of a proposal of declaration of commerciality for the D3 discoveries and BP's acquisition of a 30 per cent interest in both blocks highlights the potential of these exploration assets.

We are working closely with all stakeholders to secure the necessary approvals to resume production from the PY-3 field as soon as possible.

The Company has $37.1 million in cash and short term investments which provides Hardy with sufficient resources to meet its exploration commitments through 2012.

E P Mortimer

Chairman

23 August 2011

REVIEW OF OPERATIONS

To date, 2011 has been notable for the first natural gas discovery on the D9 exploration block, the submission of a declaration of commerciality proposal for the D3 block and the temporary shut-in of the PY-3 field from 30 July 2011. The Company's operations in India are conducted through its wholly owned subsidiary Hardy Exploration & Production (India) Inc (HEPI).

Health, Safety and Environment

The Company was the recipient of the India Coast Guard's inaugural Environmental Awards 2010 for oil handling agency category. The award is in recognition of efforts made by the Company for the implementation of oil pollution prevention measures and endeavours for the protection of the marine environment.

The Board has tailored the Group's health, safety and environment (HSE) policy and management system taking reference from world class operations to suit Indian conditions. Safety, security and emergency procedures have been incorporated into the weave of the Group's operations. The central HSE Committee and Environment Management Committees meet on a monthly basis to assess and monitor compliance. The Group regularly undertakes internal and external HSE audits, including pre-mobilisation HSE audit of rigs and vessels. The Group undertakes periodical environmental marine monitoring around production facilities and around the drilling locations. Prompt compliance with applicable regulations by the Group has been recognised by concerned agencies.

KRISHNA GODAVARI BASIN - Eastern India

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

(Hardy 10 per cent interest)

Operations - In February 2011, the D3 joint venture Operating Committee reviewed and approved for GOI submittal a Commerciality Report for the Dhirubhai 39, 41 and 52 natural gas discoveries. 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 following the GOI review, Management Committee approval could be secured by the end of 2011 after which a detailed field development plan will be prepared for submission to the MoPNG and DGH.

Appraisal of Dhirubhai 44: In February 2011, the D3 joint venture's Operating Committee reviewed and recommended 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.

Outlook - Further drilling is pending additional geological and geophysical studies, notably the PSDM processing and interpretation of 3D seismic acquired over the toe-thrust portion of the block ("pan-handle area").

Background - Situated in the emerging world class petroleum system of the Krishna Godavari Basin on the east coast of India, the D3 exploration licence encompasses an area of 3,288 km2, in water depths of 400 m to 2,200 m, and is located approximately 45 km offshore. The block is operated by Reliance, holding 60 per cent participating interest and BP holds the remaining 30 per cent.

The minimum work programme for phase one of the licence which ends in June 2013 requires the drilling of six exploration wells. To date, four consecutive gas discoveries have been made via KGV-D3-A1, B1, R1 and W1 exploration wells. The joint venture has acquired approximately 3,250 km2 of 3D seismic data over the block.

KRISHNA GODAVARI BASIN - Eastern India

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

(Hardy 10 per cent interest)

Operations - In the first half of 2011 the Company announced the results of two exploration wells on this block KG-D9-A2 and KG-D9-B3.

KG-D9-A2 (Dhirubhai - 54): On 22 June 2011, the Company announced the first natural gas discovery on the D9 block. The third well, KGD9-A2, was drilled to a total depth of 4,881 m MDRT with the objective of exploring the play fairway in the Early and Late Miocene channel levee complex in a water depth of approximately 2,700 m. Three gas bearing sand reservoirs with a gross thickness of approximately 22 m were encountered and evaluated by wireline MDT. The potential commerciality of this discovery is being ascertained through more data gathering and analysis.

KG-D9-B3: On 5 January 2011, the Company announced the plugging and abandonment 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 with gross thickness 70 and 40 m, with gas shows ranging from six per cent to nine per cent recorded while drilling. Testing was carried out with the MDT tool which indicated high water saturation in the sand packages.

The joint venture has subsequently secured a twelve month extension of the D9 licence to the end of December 2011. As per the DGH extension policy, the joint venture was required to relinquish 25 per cent of the licence at the time of the extension request. The joint venture has subsequently relinquished the south-east corner of the block and has retained approximately 8,695 km2. No identified prospects exist over the relinquished area.

Outlook - The Company anticipates the drilling of the fourth and final minimum work commitment exploration well and the submission of an appraisal plan for the KG-D9-A2 natural gas discovery (Dhirubhai 54) by the end of 2011.

Background - Situated in the Krishna Godavari Basin in India, 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 immediately adjacent to the Reliance operated D6 block, where over 2 BCF per day is being produced from Tertiary aged sediments. The D9 block is operated by Reliance holding a 60 per cent participating interest, and BP holds the remaining 30 per cent.

The joint venture has acquired 4,188 km2 of 3D seismic in the north-west quarter of the block and 2,087 km of 2D seismic over the remainder of the block. Subsequent interpretation of the seismic data has identified prospects and leads at the Pliocene, Miocene, Oligocene and Cretaceous levels.

ASSAM ARAKAN BASIN - North Eastern India

Block AS-ONN-2000/1: Exploration

(Hardy 10 per cent interest)

Operations - A request for a six month extension of phase one has been submitted to the GOI which is currently under consideration. The Company noted that the Assam block has been mentioned in the media as one of the two blocks pending GOI approval in the 23 block farmout between Reliance and BP. Pending the decision on the extension request, the Assam joint venture will take a decision to either enter into phase II, which has a minimum work commitment of one exploration well, or relinquish the block.

Background - The AS-ONN-2000/1 exploration licence is located in the north eastern state of Assam, India, north of Brahmaputra River. The exploration licence covers an area of 5,754 km2 in the districts of Darrang and Sonitpur. The block is in phase one of the three phase exploration licence. Phase one has a three year term which 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. Hardy holds a 10 per cent participating interest with Reliance holding 90 per cent as operator.

GUJARAT-SAURASHTRA BASIN - Western India

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

(Hardy 10 per cent interest)

Operations - The Operator is expecting the GOI to communicate the acceptance of the commerciality proposal submitted by the joint venture, in respect to the GS-01 Dhirubhai 33 natural gas discovery, in the near future.

In May 2010, the GS-01 joint venture submitted a proposal to DGH for declaration of commerciality for the Dhirubhai 33 natural gas discovery, and discussions have been ongoing to present. Following acceptance of the commerciality proposal by the GS-01 management committee, a development plan will be prepared and submitted to DGH. The GS-01 PSC provides the joint venture 12 months to develop a comprehensive development plan for review and approval.

In August 2011, the GS-01 joint venture submitted a proposal to the GOI for the pending development area to encompass approximately 600 km2. In the event that this proposal is accepted by the GOI, the remaining area of the exploration licence (~5,290 km2) will stand relinquished.

Background - The GS-01 exploration licence is located in the Gujarat-Saurashtra Basin, off the west coast of India, directly adjacent to the prolific Bombay High oil field. The original licence encompassed an area of 8,841 km2, with water depths varying between 80 m and 150 m.

The joint venture has previously acquired 2,216 km2 of 3D seismic data. In May 2007, the Company announced a discovery from the GS01-B1 exploration well and flow-tested the well 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. The joint venture elected not to enter phase two of the exploration licence and as a result 5,890 km2 of the block has been retained via appraisal of the GS01-B1 discovery.

CAUVERY BASIN - Eastern India

Block CY-OS 90/1 (PY-3): Producing Oil Field (Shut-in 30 July 2011)

(Hardy 18 per cent interest - Operator)

Production - Gross daily average production for the six months ended 30 June 2011 was 3,417 bbld (2010: 2,953 bbld). Gross production for the month of July 2011 averaged 3,112 bbld.

On 3 August 2011, the Company announced that the PY-3 field was temporarily shut-in on 30 July 2011 pending approvals to award a contract for the lease of the FPS currently utilised by the field. The PY-3 field will remain shut-in until the necessary approvals are in place to award a contract to the provider of the field's FPS. Once production resumes, we expect the field to continue to produce over 3,000 bbld for the remainder of 2011.

Operations - Hardy continued to work closely with all stakeholders to finalise a full field redevelopment plan to enhance production and the ultimate recovery from the PY-3 field, through the drilling of additional wells and the installation of artificial lift facilities. The Operating Committee has recommended the drilling of two further production wells and the upgrading of facilities to include gas compression for gas lift and sales gas evacuation and awaits final Management Committee approval.

Background - The PY-3 field is located off the east coast of India, 80 km south of Pondicherry in water depths of between 40 m and 450 m. The licence is operated by Hardy, covers 81 km2, and produces high quality light crude oil (49° API). The field was initially 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, 'Endeavor', which acts as a floating storage and offloading unit. There are four sub-sea wells tied back to Tahara, with one current, naturally flowing producer and two water injection wells.

CAUVERY BASIN - Eastern India

Block CY-OS/2: Exploration

(Hardy 75 per cent interest - Operator)

Operations - The Company holds a 75 per cent participating interest in its offshore block CY-OS/2 on the south east coast of India wherein a gas discovery was announced on 8 January 2007. The exploration period for the block ended on 23 March 2007 and the MoPNG was requested to extend the block for appraisal and declaration of commerciality for its non-associated natural gas (NANG) discovery until January 2012 in accordance with the provisions of the CY-OS/2 production sharing contract.

The Company has initiated a formal dispute resolution process in accordance with the PSC with the appointment of three arbitrators to seek to extend the expiry date of the licence to January 2012. In the first six months of 2011 the formal dispute resolution process to extend the expiry date of this licence was in progress.

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 -The CY-OS/2 block is located in the northern part of the Cauvery Basin immediately offshore from Pondicherry and covers approximately 859 km2. Hardy is the operator of this block. The CY-OS/2 licence comprises two retained areas. The northern area includes the Ganesha (Fan-A1) non-associated gas discovery. The southern area lies immediately adjacent to the HEPI-operated PY-3 field.

Competent Person's Report Update

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

The 2011 Competent Persons Report was been undertaken by Gaffney, Cline & Associates Ltd (GCA) and was published on 16 March 2011. The report highlights the significant prospective resource potential of the Company's Krishna Godavari Basin assets. The complete report can be downloaded from Hardy's website www.hardyoil.com.

FINANCIAL REVIEW

The Company's principal source of revenue is from the sale of crude oil production from the PY-3 field. During the six months ended 30 June 2011, the Company enjoyed a profitable period as well as had positive cash flow from operating activities (before changes in non cash working capital). The Company ended the period with cash and short term investments totalling $37.1 million and no long term debt. As a result, the Company is fully funded for its ongoing exploration programme for the remainder of 2011 and 2012.

Key Performance Indicators

* Before changes in non-cash working capital

∆ KVG-D3-W1 commenced drilling in April 2010 was prematurely suspended in May 2010 and recommenced in August 2010.

Operating Results

Production

The Company has an 18 per cent participating interest in the PY-3 field. The Company's participating interest production for the six months ended 30 June 2011 amounted to 615 barrels per day compared with 532 barrels per day for the same period in 2010. The Company announced on 3 August 2011 that the field was temporarily shut-in on 30 July 2011 due to pending approvals to award a contract to lease the existing FPS. As of this date, the field remains shut-in and the Company is working closely with all stakeholders to secure the necessary approvals to resume production as soon as possible.

Revenue

Revenue for the six months ended 30 June 2011 increased by 35.5 per cent to $7.4 million. The average price realised per bbl increased by 38.9 per cent to $109.91 during the six months ended 30 June 2011. Oil sales in the six months ended 30 June 2011 increased by 44.7 per cent to 98,075 bbl compared to the six months ended 30 June 2010. Profit oil of $3.5 million was paid to the GOI during the six months ended 30 June 2011 compared to nil for the corresponding period.

Cost of Sales

Production cost of sales increased from $1.7 million for the six months ended 30 June 2010 to $2.4 million for the current period. Cost of sales amounted to $24.49 per barrel in the first half of 2011 compared with $25.11 per barrel for the same period in 2010. Per barrel production costs amounted to $24.15 compared with $25.07 for the same period in 2010. Depletion charge amounted to $16.36 per barrel in 2011 essentially unchanged from the previous year.

Gross Profit

The Company has increased its gross profit by 79.3 per cent to $3.7 million during the first half of 2011 compared with the same period in 2010.

Administrative Expenses

Administrative expense from continuing operations remained at $3.2 million for the six months ended 30 June 2011 compared with the corresponding period.

Operating Profit (Loss) from Continuing Operations

The Company is reporting an operating profit from continuing operations of $0.5 million for the six months ending 30 June 2011 compared with a loss of $1.1 million reported for the same period in 2010.

Investment and other Income

Investment and other income amounted to $0.3 million for the six months ended 30 June 2011 compared to $0.2 million in 2010.

Taxation

No current tax was payable for the six months ended 30 June 2011 as a result of the Company's ongoing capital programme. A tax rate of 47 per cent results from the non deductibility of certain share based payments. Minimal tax relief has been provided against the pre tax loss of $1.3 million recorded for the six months ended 30 June 2010 principally as a result of the non deductibility of the share based payment charge.

Net Profit (Loss) from Continuing Operations

The Company recorded a net profit of $0.4 million for the six months ended 30 June 2011. This compares with a net loss from continuing operations of $0.9 million for the same period in 2010.

Total Comprehensive Profit (Loss)

The Company recorded total comprehensive profit of $0.4 million for the six months ended 2011 compared to a total comprehensive loss of $1.3 million for the six months ended 30 June 2010.

Cash Flow from Operating Activities

The Company generated cash flow from operating activities, before changes in non-cash working capital, of $2.5 million in the first half of 2011 compared with cash flow from continuing operations of $0.7 million for the same period in 2010. All of the Company's production costs and cash administrative expenses were fully funded by crude oil sales revenues from the PY-3 field. The favourable results arise from higher revenues principally as a result of higher crude oil prices and higher sales volumes.

Capital Expenditures

The Group's capital expenditures during the six months ended 30 June 2011 amounted to $4.2 million, compared to $2.3 million incurred for the same period in 2010. Capital expenditures were incurred principally on the drilling of the third exploration well which was the first discovery on the D9 block.

Equity Financing

The group raised $2.0 million from the issuance of equity as a result of the exercise of employee stock options.

Cash and Short Term Investments

Total cash and short term investments essentially remained at $37.1 million at 30 June 2011 compared to the end of 2010.

Financial Position

Hardy's non-current assets increased from $148.7 million at 31 December 2010 to $151.8 million at 30 June 2011. This resulted principally from the capital expenditure programme on the Company's D9 exploration block offset by depletion charges on PY-3 production.

Current assets represent the Group's cash resources, together with trade and other receivables and inventory. At 30 June 2011, of the $45.4 million of current assets, $37.1 million was represented by cash and short term investments.

Current liabilities are principally trade and other accounts payable. The level of current liabilities fluctuates significantly depending upon the timing of capital programmes. At 30 June 2011, the Company's short term liabilities were slightly higher that at the end of 2010 principally as a result of D9 drilling.

During the six months ended 30 June 2011, the Company's equity increased from $167.3 million at the end of 2010 to $170.2 million at 30 June 2011 reflecting the issue of equity and profit during the six months ended 30 June 2011.

Principal Risks and Uncertainties

Any of the risks and uncertainties discussed in this document, could have a material adverse effect on the Group's business. In addition, the risks set out below may not be exhaustive and additional risks and uncertainties, not presently known to the Company, or which the Company currently deems immaterial, may arise or become material in the future. In particular, the Company's performance might be affected by changes in market and/or economic conditions and in legal, regulatory and tax requirements.

The principal risks and uncertainties facing the Group as at 15 March 2011, their potential impact and the mitigation strategies developed were detailed in the Company's 2010 Annual Report and Accounts (available on our website www.hardyoil.com). Most of the risks and uncertainties which were identified at the year-end have not changed and still remain appropriate for the second half of 2011. Key risks relating to the following were identified;

·; Strategic risk is generally described as "ineffective or poorly executed strategy fails to create shareholder value or fails to meet stakeholder expectations". Asset portfolio over-weighted to long-cycle exploration licence; overdependence on a single partner and lack of control to drive value creating activities.

·; Financial risk is generally described as "assets performance and excessive leverage results in the Group unable to meet its financial obligations". Cost overruns of exploration programme; reliance on a single producing well for revenue and; relinquishment of assets such as the CY-OS/2 licence may result in an impairment provision.

·; Operational risk is generally described as "operational event impacting staff, contractors, communities or the environment leading to loss of reputation and/or revenue". An accident or blowout could occur during offshore drilling operations; sustained sub-commercial exploration results; reliance on a single producing asset; limited life of field in absence of further development and failure to secure budgetary approval for PY-3 Phase III drilling.

·; Compliance risk is described as "the overall external political, industry or market environment may negatively impact the Company's ability to independently grow and manage its business". Deteriorating stakeholder sentiment and changing regulatory and political environment in India.

Key Risks for the second half of 2011

The Board has identified the following items as key risks to the Company in the near-term. These risks are presented in no particular order.

General exploration, development and production risks - The Group's strategy is predominantly driven by the exploration, appraisal, development and production of its existing assets. There are risks inherent in the exploration, appraisal, development and production of oil and gas reserves and resources. Whilst the rewards can be substantial, there is no guarantee that exploration will lead to further commercial discoveries. Exploration and production activities by their nature involve significant risks.

Executing exploration drilling programme - The Group's exploration plans comprise activities primarily on non-operated blocks. The timing of execution of activities may not commence as currently forecasted and significant delays may be experienced. As well, the exploration focus of the Group's 2011 work programme may result in the failure to discover hydrocarbons in commercial quantities.

CY-OS/2 block arbitration - With respect to the Group's Ganesha (CY-OS/2) non-associated natural gas discovery, HEPI and the Government of India have initiated formal dispute resolution process, in accordance with the CY-OS/2 PSC. Intangible assets include an amount of $83.5 million 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 Company had submitted a request for the GOI 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. The MOPNG has informed HEPI that in their opinion the discovery is classified as an oil discovery and not a NANG discovery. In the event that the arbitration ruling for an extension of the CY-OS/2 licence is unsuccessful, the Company would no longer hold a commercial interest in the exploration licence and capitalised expenditure would be subject to impairment testing.

Prolonged shut-in of the PY-3 field - The Company's only producing asset, the PY-3 oil field, was temporarily shut-in on 30 July 2011. Resumption of production is subject to the PY-3 Management Committee approving a proposed redevelopment plan which includes the awarding of a five year contract for the existing FPS. In the event that such approval is further delayed the current owner of the FPS may choose to demobilise the facilities. Under this circumstance the field would remain shut-in until a suitable alternative FPS is procured.

Unplanned shut-in of the PY-3 field - In the event that PY-3 field recommences production in the short term, the Company's revenue will principally be generated from a single offshore oil field which is producing from a single well. In the past the field has experienced extended unplanned shut-ins due to facility and weather related issues. In the event that the PY-3 field experiences an unplanned shut-in due to subsurface or surface issues the Company's revenue may be significantly impacted.

Loss of key personnel - The Company depends to a large extent on the efforts and continued employment of the management team, the loss of the services of these officers and other key personnel could adversely affect the Company's business. Further, the success of drilling operations and other activities integral to its business will depend in part on the ability to attract and retain experienced geologists, engineers and other professionals. Competition for experienced geologists, engineers and other professionals is extremely intense. The Company's ability to compete in the upstream oil and gas exploration and production industry will be harmed to the extent that the Company and its subsidiaries are unable to retain and attract experienced technical personal.

Timeliness of regulatory approvals - Under the terms of the PSCs, major capital expenditures and annual operating budgets require the approval of the Management Committee, which includes joint venture partners and GOI representatives. Prolonged delays in securing such approvals would have a material impact on the monetisation of the Company's oil and gas reserves.

Relinquishment of exploration acreage - Some of the Company's exploration assets are at or near the end of the first of three phases of exploration provided for in the India PSC's. The Company has options to enter into phase two, which have pre-agreed minimum work commitments, or relinquish the area of the licence not covered by an ongoing appraisal programme or the area allocated for development of a commercial discovery.

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 Company's revenue is principally generated by the sale of oil. Should there be a significant fall in global oil prices the Company's revenue may be significantly impacted.

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 the United Kingdom; therefore the Group is exposed to foreign exchange risk against Indian Rupees, and UK Sterling.

Liquidity risk management and going concern

At 30 June 2011, the Company had liquid resources of approximately $37.1 million, in the form of cash and short term investments, which is available to meet ongoing capital, operating and administrative expenditures. At the present time, the Company does not have any short-term or long-term debt.

Emphasis of Matter - Status of CY-OS/2 Discovery Block

The auditors have provided an "emphasis of matter" comment in their independent review 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 2 of the interim consolidated financial statements.

RESPONSIBILITY STATEMENT

We confirm that to the best of our knowledge:

• the interim consolidated financial statements have been prepared in accordance with International Accounting Standards 34, Interim Financial Reporting, as adopted by the EU; and

• give a true and fair view of the assets, liabilities and loss of the group; and

• the Interim report includes a fair review of the information required by DTR 4.2.7R of the Disclosure and Transparency Rules, being an indication of important events that have occurred during the first six months of the financial year and their impact on the set of interim consolidated financial statements; and a description of the principal risks and uncertainties for the remaining six months of the year.

On behalf of the Board

Dinesh Dattani FCA

Finance Director

23 August 2011

INDEPENDENT REVIEW REPORT TO HARDY OIL and GAS plc

Introduction

We have been engaged by the company to review the interim consolidated financial statements in the half yearly management report for the six months ended 30 June 2011 which comprises the consolidated statement of comprehensive income, the consolidated statement of changes in equity, the consolidated statement of cash flows, the consolidated statement of financial position, and the related explanatory notes. We have read the other information contained in the half yearly management report and considered whether it contains any apparent misstatements or material inconsistencies with the information in the interim consolidated financial statements.

Directors' Responsibilities

The half yearly management report is the responsibility of, and has been approved by, the directors. The directors are responsible for preparing the half yearly management report in accordance with the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.

As disclosed in note 1, the annual consolidated financial statements are prepared in accordance with IFRS as adopted by the European Union. The interim consolidated financial statements included in this half yearly management report have been prepared in accordance with International Accounting Standard 34, Interim Financial Reporting, as adopted by the European Union.

Our Responsibility

Our responsibility is to express to the Company a conclusion on the interim consolidated financial statements in the half yearly management report based on our review.

Scope of Review

We conducted our review in accordance with International Standard on Review Engagements (UK and Ireland) 2410, Review of Interim Financial Information Performed by the Independent Auditor of the Entity issued by the Auditing Practices Board for use in the United Kingdom. A review of interim consolidated financial information consists of making enquiries, primarily of persons responsible for financial and accounting matters, and applying analytical and other review procedures. A review is substantially less in scope than an audit conducted in accordance with International Standards on Auditing (UK and Ireland) and consequently does not enable us to obtain assurance that we would become aware of all significant matters that might be identified in an audit. Accordingly, we do not express an audit opinion.

Conclusion

Based on our review, nothing has come to our attention that causes us to believe that the interim consolidated financial statements in the half yearly management report for the six months ended 30 June 2011 are not prepared, in all material respects, in accordance with International Accounting Standard 34 as adopted by the European Union and the Disclosure and Transparency Rules of the United Kingdom's Financial Services Authority.

Emphasis of matter - Request for an extension of an exploration licence

In forming our conclusion on the interim consolidated financial statements, which is not qualified, we have considered the adequacy of the disclosures made in note 2 (i) to the interim consolidated financial statements concerning the process of arbitration with the Government of India for an extension of its exploration licence in block CY-OS/2. In the event that the group is not successful in the arbitration, the exploration expenditure capitalised in respect of this block will be subject to impairment testing. No adjustment has been made to the carrying value of this capitalised expenditure.

CROWE CLARK WHITEHILL LLP

London

23 August 2011

HARDY OIL AND GAS plc

Consolidated Statement of Comprehensive Income

HARDY OIL AND GAS plc

Consolidated Statement of Changes in Equity

HARDY OIL AND GAS plc

Consolidated Statement of Financial Position

As at 30 June 2011

HARDY OIL AND GAS plc

Consolidated Statement of Cash Flows

1. Accounting Policies

Basis of preparation

These interim consolidated financial statements are for the six months ended 30 June 2011 and have been prepared in accordance with International Accounting Standard 34 "Interim Financial Statements". The accounting policies applied are consistent with International Financial Reporting Standards (IFRS) adopted for use by the European Union. The accounting policies and methods of computation used in the interim consolidated financial statements are consistent with those used in the Annual Report for 2010 and are expected to be applied for the year ended 31 December 2011.

The interim results for the six months ended 30 June 2011 are not necessarily indicative of the results to be expected for the full year 2011.

2. Critical Accounting Estimates and Judgments

Estimates and judgments are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. The Group makes estimates and assumptions concerning the future. The resulting accounting estimates may differ from the related actual results. The estimates and assumptions that have a significant risk of causing a material adjustment to the carrying amounts of assets and liabilities within the financial year are addressed below.

i) Intangible assets- exploration

The Group holds a 75 per cent participating interest in the block CY-OS/2 offshore the south east coast of India. Intangible assets include an amount of US$83,530,141 with respect to exploration expenditures on the block wherein a gas discovery was announced on 8th January 2007. The exploration period for the block ended on 23 March 2007 and the Government of India (GOI) has been requested to extend the block in terms of the production sharing contract ("PSC") for appraisal and declaration of commerciality for its Non-Associated Natural Gas ("NANG") discovery until 7th January 2012.

This request was not accepted by GOI and the matter is before the arbitration tribunal for adjudication.

The Group believes that in line with article 30.5 of the PSC, the termination being the subject matter of proceedings before the arbitral tribunal under Article 33, the termination shall not take place as long as the proceedings continue and thereafter the arbitral award will decide the issue. Therefore, the intangible assets arising from expenditure on this block continues to be recognized in full and the Directors do not believe that any impairment of these costs has arisen as at 30 June 2011.

ii) Decommissioning

The liability for decommissioning is based on estimates of the costs of decommissioning that will arise in the future. Significant changes in costs as a result of technical advancement and other factors can result in material change to this provision.

iii) Depletion

Depletion calculations are based on best estimates of commercial reserves existing as at the balance sheet date. The determination of commercial reserves is based on assumptions which include those relating to the future prices of crude oil and natural gas, capital expenditure plans, cost of production and other factors. Any changes in these assumptions could result in a material change in the depletion charge or the carrying value of associated assets.

3. Earnings per share

Earnings per share for continuing operations are calculated on a profit of US$376,422 (June 2010: loss US$1,305,221) and a weighted average number of ordinary shares of 72,240,478 (June 2010: 68,497,770).

The diluted earnings per share for continuing operations are calculated on a profit of US$376,422 for the period ended on 30 June 2011 (June 2010: loss US$1,305,221) on a weighted average of 74,036,877 ordinary shares for the period ending on 30 June 2011 (June 2010; 71,098,535). The outstanding share options as on 30 June 2011 are 4,453,399, out of which 2,657,000 share options the strike price exceeds the average market price. Accordingly, the dilutive potential of share option is considered as 1,796,399.

4. Segment Analysis

The Group is organized into two business units: India and the United Kingdom. The India business unit focuses on exploration and production of oil and gas assets in India and is operated by its subsidiary undertaking Hardy Exploration & Production (India) Inc. Hardy Oil and Gas plc is based in the United Kingdom and executes corporate functions and undertakes treasury management. Nigeria business unit was discontinued on 27th October 2010.

The business of the group does not have any segments that are seasonal or cyclical in nature.

5. Taxation

Indian operations of the Group are subject to tax rate of 42.23 per cent which is higher than UK and US corporation tax rates. To the extent that the Indian profits are taxable in the US and / or the UK, then those territories should provide relief for Indian taxes paid, principally under the provisions of double taxation agreements. Based on the current expenditure plans, the Group anticipates that the tax allowances will continue to exceed the depletion charge of each year for the foreseeable future, though the timing of related tax relief is uncertain.

6. Intangible assets - exploration

Reference is made to note 2 - Critical accounting estimates and Judgments with respect to carrying value of intangible assets - exploration.

7. Property, plant and equipment

Oil and gas assets represent interest in producing oil and gas assets failing under the India Cost pool. The Group has sold its Nigerian oil and gas assets in the fourth quarter of 2010. Other fixed assets consist of office furniture, computers, workstations and office equipment.

8. Share Capital

The Company has authorized share capital of 200 million US$0.01 ordinary shares.

Changes in issued and fully paid ordinary shares during the six months ended 30 June 2011 are as follows:

Shares issued during the year consist of 21,971 restricted shares issued to non-executive directors on 7th January 2011 and 815,700 shares issued in April 2011 to the non-executive director and the employees of Nigerian operations who had resigned in the previous year.

9. Share Options

Changes in outstanding share options during the six months ended 30 June 2011 are summarized below:

10. Contingent Liabilities

Bank guarantees for US$4,857,150 have been issued to Government of India as at 30 June 2011. The guarantees were obtained by placing a fixed deposit of Rs 38,963,991 (US$872,068) with a bank with the interest rate of 8 per cent.

11. Dividends

The board of directors do not recommend the payment of an interim dividend for the period ending 30th June 2011.

12. Approval of Interim Consolidated Financial Statements

These interim consolidated financial statements have been approved by the board of directors on 23 August 2011.

DEFINITIONS & GLOSSARY OF TERMS:

Assam block licence AS-ONN-2000/1

Board the Board of Directors of Hardy Oil and Gas plc

BP BP plc

the Company Hardy Oil and Gas plc

CPR Competent Persons Report

D3 licence KG-DWN-2003/1 awarded in NELP V

D9 licence KG-DWN-2001/1 awarded in NELP III

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 41 gas discovery on KGV-D3-R1 well

Dhirubhai 52 gas discovery on KGV-D3-W1 well

Dhirubhai 54 gas discovery on KG-D9-A2 well

DGH Directorate General of Hydrocarbons of the MoPNG

FPS floating production system

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

GCA Gaffney, Cline & Associates Ltd.

GOI Government of India

Group the Company and its subsidiaries

GS-01 licence GS-OSN-2000/1

Hardy Hardy Oil and Gas plc

HEPI Hardy Exploration & Production (India) Inc

HSE Health Safety and Environment

LSE London Stock Exchange

Management Committee as per India PSC the committee is the authority to approve annual budgets and capital programmes, members comprise joint venture partners and two Government of India appointed representatives

MoPNG Ministry of Petroleum and Natural Gas of the Government of India

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

Operating Committee as per India PSC's the committee reviews and recommends annual budgets and exploration, appraisal and development programmes to the Management Committee

Ordinary Shares 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

Glossary of terms:

$ United States dollars

2D/3D two dimensional/three dimensional

API° American Petroleum Institute gravity

bbl stock tank barrel

bbld stock tank barrel per day

DST drill stem test

DWT dead weight tonne

GOR gas to oil ratio

km kilometre

km2 kilometre squared

lkm line kilometre

m metre

MD measured depth

MDT modular formation dynamics tester

MMscfd million standard cubic feet per day

MMbbl million stock tank barrels

MMbbld million stock tank barrels per day

NANG non associated natural gas

Prospective Resources those quantities of petroleum which are estimated, as of a given date, to be potentially recoverable from undiscovered accumulations

PSDM pre-staked depth migration processing is a model-based seismic imaging methodology that works well for complex geological structures. PSDM is more time consuming to process than conventional time migration processing, but is better at determining sub-surface structure

psi pounds per square inch

scf standard cubic feet

scfd standard cubic feet per day

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