HDY.L Regulatory News (HDY)

7 March 2012

Hardy Oil and Gas plc

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

2011 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 2011 and provides an outlook for 2012.

# All financial amounts in US dollars unless otherwise stated.

Corporate

2011 operational summary

2011 financial summary

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

2012 Outlook

Commenting on the results, Alasdair Locke, Chairman of Hardy said:

"Our D3 exploration licence in the Krishna Godavari Basin remains the core to our organic growth potential. Through 2012 we will continue to collaborate actively with our partners Reliance and BP to optimise the exploration programme for this highly prospective block.

Following the appointment of Ian MacKenzie, as Chief Executive Officer, we have initiated a comprehensive review of our long-term strategic goals and objectives in order to realise value for shareholders. We look forward to reporting the results of the review in due course."

For further information please contact:

2011 FULL YEAR RESULTS STATEMENT

Overview

During 2011, the Company accomplished a number of objectives. The exploration programme on the Company's two blocks in the Krishna Godavari Basin progressed by concluding the drilling of two further exploration wells. As a result of this activity, we announced the first gas discovery in the D9 block. The D3 joint venture submitted a declaration of commerciality proposal for the Dhuribhai 39, 41 and 52 discoveries on the D3 block to the Government of India ('GOI') for review. The GS-01 joint venture adopted the declaration of commerciality proposal for the Dhuribhai 33 discovery. Discussions are continuing with partners and contractors in relation to the PY-3 field development options. We are pleased with the progress made on our D3 exploration block which will be the catalyst for value creation during 2013.

We are initiating a comprehensive review of our long-term strategic goals and objectives. However, the Company remains in a strong working capital position with which to fund its planned work activity.

Key financial results

Revenue was down from $13.2 million in 2010 to $11.3 million in 2011 due to lower production levels (the PY-3 field was shut-in for five months in 2011) but partly offset by the higher average realised oil price. Administrative expenses increased to $6.9 million compared to $3.3 million in 2010. The Company made an operating loss from continuing operations of $4.7 million in 2011.

The Company has made a change to its accounting policy by adopting the successful efforts basis accounting policy for its oil and gas assets in 2011. As a result Hardy has restated the Company's consolidated financial statements for 2010. We believe that this change aligns our accounting policy with international peers and provides a better reflection of the results of our activities and financial position.

The Group started 2011 with cash reserves of $36.5 million. Net cash used in continuing operating activities (before changes in non cash working capital, tax paid, interest and investment income and finance costs) was $0.9 million. Proceeds from option exercise were $2.0 million. As a result, the Group's cash reserves at the end of 2011 remained unchanged at $36.5 million. The Group remains in a strong financial position with no debt.

Board changes

The Board recently underwent a significant reorganisation which has resulted in the appointment of three new Directors and the planned retirement of three other Non-Executive Directors. The Chairman, Paul Mortimer had expressed his intention to step down from his role in 2011. The Nomination Committee initiated a process which resulted in my appointment in January 2012. Paul has been Chairman for over nine years, from before the Company floated on the London Exchange, and we very much appreciate all his wise support and guidance.

On 31 August 2011 Dinesh Dattani ceased to be the Finance Director of Hardy. We would like to thank Dinesh for his considerable contributions to Hardy over the past four years.

At the time of my appointment the Company announced Yogeshwar Sharma's intention to step aside as Chief Executive Officer and assume a non-executive role with the Company. On 1 March 2012 we were pleased to announce the appointment of Ian MacKenzie. Ian has a proven track record of delivering results in a competitive industry. We are confident that his experience and leadership qualities will ensure we are successful in implementing the recommendations of the review.

We are grateful to Yogeshwar Sharma, one of the founders of the Company, for his invaluable contribution over many years and we are particularly grateful that he will provide continuity in this period of transition as a Non-Executive Director.

Prior to my appointment, Ian Bruce and Carol Bell had indicated that they did not intend to put themselves forward for re-election at the Company's next Annual General Meeting and would retire from the Board of Hardy. Ian Bruce and Carol Bell have served as Directors for over four and six years respectively. On behalf of the Board I would like to thank them for their contribution over their tenure.

The Company announced the appointment of Peter Milne as a Non-Executive Director on 1 March 2012. Peter has a proven track record in the oil sector having been the head of finance for the largest UK headquartered drilling contractor for over 15 years. His financial expertise and experience will fill a core competency gap. It is intended that Mr Milne will be designated the Senior Independent Non-Executive Director and assume the Chairmanship of the Audit Committee following his re-election at this year's Annual General Meeting.

Year end audit

As in last year's accounts, the auditors have provided an emphasis of matter comment in their audit report with reference to the uncertainty concerning the Group's request to the GOI for an extension of its exploration licence in block CY-OS/2 as disclosed in note 2 and 15 to the consolidated financial statements. In the event that Hardy's application for an extension of the CY-OS/2 licence was to be unsuccessful, the capitalised expenditure of $51 million will be subject to impairment testing.

Outlook

The declaration of commerciality proposal for the D3 block is being reviewed by the Government of India and this process will continue through 2012. Reprocessing of seismic covering the eastern area of the D3 block is also expected to continue through 2012. As a result drilling on the D3 block is expected to re-commence in the first quarter of 2013.

The D3 exploration licence in the Krishna Godavari Basin remains at the core of our organic growth potential. 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. Through 2012 we will continue to collaborate actively with our partners Reliance and BP to optimise the exploration programme for this highly prospective block.

With the recent adoption of the declaration of commerciality for the GS-01 block we have until the end of the year to submit a field development plan for the Dhuribhai 33 natural gas discovery. The D9 joint venture has until July 2012 to submit an appraisal programme for the KG-D9-A2 gas discovery.

An early priority for PY-3 will be to determine, with partners and contractors, a suitable way forward to optimise value for all stakeholders.

Following the appointment of Ian MacKenzie, as Chief Executive Officer, we have initiated a comprehensive review of our long-term strategic goals and objectives in order to realise value for shareholders. We look forward to reporting the results of the review in due course but in any event, no later than at the time of our half-year results in September 2012. The Company remains in a strong working capital position from which to fund its planned work activity.

Alasdair Locke

Chairman

6 March 2012

REVIEW OF OPERATIONS

The highlights of operations in 2011 were the drilling of the second and third exploration wells on the D9 exploration block, the submission of a declaration of commerciality proposal for the D3 block, and the shut-in of the PY-3 field from 30 July 2011 due to lack of approval from the field's Management Committee to award a contract for its current facilities. The Company's operations in India are conducted through its wholly owned subsidiary Hardy Exploration & Production (India) Inc. ('HEPI').

2011 Performance

Health, Safety and Environment - The Company was the recipient of one of the India Coast Guard's inaugural Environmental Awards 2010 in the 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.

Production - The PY-3 field (Hardy interest 18 per cent) performed as projected until the field was shut-in at the end of July 2011 pending approvals to award a contract for the lease of the floating production system currently utilised by the field.

Prior to the shut-in the field had produced at an average gross daily rate of over 3,300 bbld. For the year, the average gross daily production was 1,953 barrels per day (bbld) (net: 352 bbld) compared to the Company's forecast of 3,000 bbld. The Company had targeted securing the necessary budgetary approvals in mid 2011 in order to commence the drilling of two further producing wells (Phase III) in the PY-3 field in 2012. Throughout 2011 the Company worked closely with all stakeholders to advance the approval process.

Discussions are continuing with partners and contractors in relation to field development options.

Exploration - At the beginning of 2011 the Company had planned for the drilling of at least two exploration wells in the Krishna Godavari Basin. The Company subsequently concluded the drilling of two exploration wells on the D9 exploration block (Hardy interest 10 per cent) in the Krishna Godavari Basin. The KG-D9-B3 exploration well recorded gas shows with good quality reservoir sands while drilling, however the MDT testing indicated high concentration of mobile water in the sands and the well was plugged and abandoned. The KG-D9-A2 discovery well was drilled to a total depth of 4,881 m MDRT, and three gas bearing sand reservoirs with a gross thickness of approximately 22 m were encountered and evaluated by wireline MDT.

After carefully considering the block's low prospectivity in conjunction with the logistical challenges of the area, the joint venture elected to relinquish the Assam exploration block.

Development - In February 2011, the D3 joint venture (Hardy interest 10 per cent) submitted a proposal for the declaration of commerciality for the Dhirubhai 39, 41 and 52 natural gas discoveries to the Government of India. The proposed development plan provides for a dry gas, subsea cluster development with the flexibility to add in additional zones and future area discoveries.

Near the end of 2011, the GS-01 (Hardy interest 10 per cent) declaration of commerciality proposal was adopted by the management committee and the joint venture has until the end of 2012 to submit a detailed field development plan.

Through 2011 the Company continued to participate in a formal dispute resolution process to extend the expiry date of the CY-OS/2 licence (Hardy interest 75 per cent). A ruling is expected to be issued in the second half of 2012.

The table below provides a brief comparison of our stated operational objectives for 2011 and our subsequent accomplishments through the year:

Outlook for 2012

D3 - The joint venture will continue to undertake a number of geotechnical studies in 2012. Exploration activity is now focused on assessing the potential of the eastern area and high grading prospects to test deeper play types within the central portion of the block. The D3 operator indicated that the fifth exploration well is expected to commence drilling in the first quarter of 2013 and the sixth and final commitment well no later than the second quarter of 2013. Prospects in the eastern area and the Phase I areas will be evaluated after the PSDM processing to prioritise and plan the future drilling program.

D3 - Earlier this year the D3 joint venture Operating Committee reviewed and recommended a Commerciality Report for the Dhirubhai 39, 41 and 52 natural gas discoveries subject to a Government of India review. The proposed development is a dry gas, subsea cluster development with the flexibility to add in additional discoveries. The Government of India's review is ongoing and a decision is expected by the end of 2012.

PY-3 - An early priority for PY-3 will be to determine, with partners and contractors a suitable way forward to optimise value for all stakeholders.

D9 - Following the KG-D9-A2 natural gas discovery in July 2011, the joint venture was unable to drill the fourth and final exploration well within the remaining exploration time period. The joint venture is reviewing the potential of the discovery for further activity and has until July 2012 to submit an appraisal programme. In the absence of the submission of an appraisal programme the block will stand relinquished.

GS-01 - Following approval of the declaration of commerciality the GS-01 joint venture has 12 months to submit a detailed field development plan. The Company will work closely with the operator to formulate the optimal development plan in a timely manner.

Competent persons report update

The Company had previously committed to commission the updating of a competent person's report ('CPR') on an annual basis in conjunction with the year-end financial reporting process. Due to limited drilling activity in 2011 and the uncertainty surrounding the recommencement of production in the PY-3 asset, the Company took the decision to postpone the updating of a CPR until later in the year.

A summary of the Company's 2011 CPR is provided below. A detailed summary of the report is provided at the end of this announcement and the complete report can be downloaded from www.hardyoil.com.

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

Subsequent to the effective date of the Company's 2011 CPR, the Company has drilled two wells on the D9 block;

·; KG-D9-B3 which was targeting Pilocene channel sands and was plugged and abandoned

·; KG-D9-A2 which was targeting several Miocene sands announced a natural gas discovery in the Upper Miocene sands.

ASSET REVIEW

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

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

(Hardy 10 per cent interest)

Operations - Declaration of Commerciality - Earlier this year the D3 joint venture Operating Committee reviewed and recommended a Commerciality Report for the Dhirubhai 39, 41 and 52 natural gas discoveries subject to a Government of India review. The proposed development is a dry gas subsea cluster development with the flexibility to add in additional discoveries. The Government of India review is ongoing and a decision is expected by the end of the year.

Exploration - Following the Government of India's approval of Reliance's 30 per cent participating interest farmout to BP, we have been delighted with BP's contribution to the prospect generation and evaluation process. The ongoing geotechnical evaluation of the block integrated with new regional data has identified a number of additional prospects and leads. The new prospectivity is primarily focused on thermogenic sourced plays. We expect further clarification of the plays and associated prospectivity to coincide with the ongoing interpretation in the central area of the block and the PSDM seismic processing in the east portion of block.

2012 Outlook - The joint venture will continue to undertake a number of geotechnical studies in 2012. Exploration activity is now focused on assessing the potential of the eastern area of the block and high grading prospects to test deeper play types within the central portion of the block. There have been a number of delays in the awarding of a contract to provide PSDM processing. As a result, the D3 operator indicated that the fifth exploration well is expected to commence drilling in the first quarter of 2013 and the sixth and final commitment well no later than the second quarter of 2013. Prospects in the eastern area and the Phase I areas will be evaluated after the PSDM processing to prioritise and plan the future drilling programme.

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 D3 block is operated by Reliance which holds a 60 per cent participating interest with BP holding 30 per cent and Hardy the remaining 10 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.

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

(Hardy 10 per cent interest)

Operations - In 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 from its third well, KG-D9-A2. The well 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 2,703 m. Three gas bearing sand reservoirs with a gross thickness of approximately 22 m were encountered and evaluated by wireline MDT.

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 a gross thickness of 70 m and 40 m, 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 a high concentration of mobile water in the sand packages and the well was plugged and abandoned.

2012 Outlook - Following the KG-D9-A2 natural gas discovery in July 2011, the joint venture was unable to drill the fourth and final exploration well within the remaining exploration period. The joint venture is reviewing the potential of the discovery for further activity and has until July 2012 to submit an appraisal programme. In the absence of the submission of an appraisal programme the block will stand relinquished.

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 1 BCF per day is being produced from Tertiary aged sediments. The D9 block is operated by Reliance which holds a 60 per cent participating interest with BP holding 30 per cent and Hardy the remaining 10 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.

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

(Hardy 10 per cent interest)

Operations - The GS-01 joint venture secured the Government of India's approval for a declaration of commerciality proposal for the Dhirubhai 33 discovery (GS01-B1) (drilled in 2007) which flow-tested at a rate of 18.6 mmscfd gas with 415 bbld of condensate through a 56/64 inch choke at flowing tubing head pressure of 1,346 psi.

2012 Outlook - The joint venture will commence work with the intention of submitting a detailed field development plan, for the Dhirubhai 33 natural gas discovery, prior to the end of the year.

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) with water depths varying between 80 m and 150 m. The joint venture retained a 600 km2 area for future development activities by relinquishing the balance area of 5,290 km2. The joint venture has previously acquired 2,216 km2 of 3D seismic data. Upon completion of Phase I of the exploration programme the joint venture elected not to proceed to the second phase of exploration.

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

(Hardy 18 per cent interest - Operator)

Production - Gross average daily field production for the year ended 31 December 2011 was 1,953 bbld (2010: 3,156 bbld; 2009: 1,535 bbld). Up until the time of shut-in the field had produced at a gross average rate of approximately 3,350 bbld. The production facilities' uptime performance was 58 per cent (2010: 93 per cent). The decrease in production was the result of an extended unplanned shut-in on 30 July 2011 as a result of not getting timely approval to extend the FPU contract and the subsequent falling out of class of the vessels.

The field has remained shut-in in for the beginning of 2012. Should production recommence we anticipate that the PY-3 field will be capable of an initial average gross daily rate of approximately 3,000 bbld and approximately 8,000 bbld with the drilling of two additional wells.

Development - In 2011, the PY-3 joint venture had been seeking approval from the Government of India to award a five year contract to the incumbent facilities providers which was not approved at the Management Committee level. The terms and conditions of the recommended contract had been derived from industry benchmarking and negotiation with the incumbent facility ownership.

2012 Outlook - An early priority for PY-3 will be to determine, with partners and contractors a suitable way forward to optimise value all stakeholders. To date the joint venture has been providing the current offshore facilities with various support vessels and auxiliary services. In the absence of securing the necessary approvals to recommence production in a timely manner an extended shut-in of the field may result.

The field is currently capable of producing at a gross daily rate of over 3,000 bbld and at 8,000bbld with two additional wells. We project that the current producing well is capable of producing for a further 18 months. Production beyond this period will require the drilling of additional wells and the installation of gas lift facilities.

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)

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

2012 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 2012.

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.

Block AS-ONN-2000/1 (Assam): Relinquished in 2011

(Hardy 10 per cent interest)

Operations - The Assam block was awarded under India's NELP II bid round in 2000. The block is located on the western, undrilled margin of the Assam Basin. The nearest production is approximately 50 km distance. Hardy held a 10 per cent participating interest with the block operated by Reliance.

Following seismic acquisition, processing and interpretation, the geologic analysis of the area identified two structural prospects. The Company's published CPR listed gross best estimate prospective resources of 20 MMbbl and 5 MMbbl with a geological chance of success ('GCOS') of 10 per cent, due to petroleum system uncertainty in this undrilled part of the basin.

After carefully considering the block's low prospectivity in conjunction with the logistical challenges of the area, the joint venture has elected to relinquish the block.

FINANCIAL REVIEW

During 2011, the Company recorded a decrease in revenue due to the PY-3 field being shut-in from 31 July 2011. This has resulted in a decrease in gross profit and an operating loss (compared with a profit in 2010). Hardy completed the year with cash and short-term investments of $36.5 million and has no debt.

Accounting policy change

The Company has changed to the successful efforts method of accounting for its oil and gas assets which allows for the capitalisation of successful exploration costs, whereas the dry hole and its associated geological and geophysical costs are written-off. Accordingly, Hardy has recorded a charge for unsuccessful exploration costs of $55.9 million which had previously been included in intangible assets. The Company has also restated the Company's consolidated financial statements for 2010.

Key Performance Indicators

The Company undertook a review of its disclosed key performance indicators. As a result, the Company identified two financial and four non-financial measures as key performance indicators for Hardy. The measures reflect the Company's exploration focused strategy, the importance of a positive cash position and our underlying commitment to ensuring safe operations. The key performance indicators adopted in 2011 are summarised below;

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

We met several of our targets for 2011 but fell short of one financial and two operating targets.

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 2011 amounted to 1,953 bbld compared with 3,156 bbld for 2010. The decrease was due to the shut-in of the PY-3 field on 31 July 2011 due to the Floating Production System ('FPS') falling out of contract and class validity.

Revenue from oil sales (after profit oil) decreased to $11.1 million in 2011 compared to $12.9 million in 2010. The average price realised per barrel increased by 35 per cent from $81.71 during 2010 to $110.54 in 2011. Average daily sales amounted to 392 bbld in 2011 compared with 525 bbld in 2010.

Cost of Sales

Production costs decreased from $5.3 million in 2010 to $3.7 million in 2011 as a result of reduction of charter hire charges to FPS to seven months instead of 12 months in 2010. Average cost per barrel including depletion is $40.87 per barrel in 2011 compared with $41.63 per barrel in 2010. Production cost per barrel remained relatively unchanged at $28.49 in 2011 compared with $25.66 in 2010.

Unsuccessful exploration costs

As a result of the Company's change in accounting policy to the SEM, the unsuccessful exploration well costs and the associated geological and geophysical costs of $3.4 million for the year 2011, $1.8 million for 2010 and $50.7 million up to 2009 were charged to the Statement of Comprehensive Income. The adjustments primarily relate to nine exploration wells drilled in prior years including two exploration wells on the block CY-OS/2 block (TRL and Fan E), three exploration wells on the GS-OSN-2000/1 block (AI, S1 and M1) and two exploration wells on the D9 block (A1 and B3), and associated geological and geophysical expenses of the block AS-ONN-2000/1.

Gross Profit

The Company realised a gross profit of $2.2 million in 2011 compared with a profit of $3.1 million in 2010. The decrease is principally the result of lower production which was partly mitigated by higher average crude oil price realised in 2011.

Administrative Expenses

Administrative expenses increased from $3.3 million in 2010 to $6.9 million in 2011. This increase is mainly due to a provision for possibly irrecoverable costs of $2.3 million from the operated blocks and a loss on exchange of $0.9 million.

Operating Loss

The Company is reporting an operating loss from continuing operations of $4.7 million in 2011 compared with an operating loss of $0.2 million in 2010.

Interest and Investment Income

Investment and other income in 2011 remained unchanged from 2010 at $0.4 million.

Finance Costs

Finance costs principally include the cost of providing bank guarantees to the Government of India required by the provisions of production sharing contracts and the unwinding of the decommissioning cost.

Loss before Taxation

The Company has recorded a loss before taxation from continuing operations of $4.6 million compared to a nominal profit before taxation in 2010. This results principally from lower revenues and higher general and administrative expenses in 2011 and the change in the accounting policy from full cost to successful effort method.

Taxation

The Company has recorded a tax credit of $2.7 million during 2011 compared to a tax charge of $0.3 million in 2010.

Loss from Continuing Operations

As a result, the Company recorded a loss for the year from continuing operations of $1.9 million compared to a loss of $0.2 million for 2010.

Cash Flow from Operating Activities

During 2011, the Company had a negative cash flow from continuing operations activities, before changes in non-cash working capital, amounting to $0.9 million against a positive cash flow of $4.0 million in 2010.

Financing Activities

During 2011 the Company realised $2.0 million in proceeds from the execution of various stock options. 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. 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 remained unchanged at $36.5 million at the end of 2011. The Company does not have any debt.

Summary Statement of Financial Position

Hardy's non-current assets decreased from $101.6 million in 2010 to $97.3 million in 2011. Current assets represent the Group's cash and short-term investments, trade and other receivables and inventory and have decreased from $43.6 million to $39.7 million. At the end of 2011, of the $39.7 million of current assets, $36.5 million are represented by cash and short-term investments. Current liabilities are principally trade and other accounts payable which are $6.1 million at the end of 2011 compared to $13.4 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 2011, the Group had cash resources of $36.5 million and had no debt.

Dividends 

The Directors 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 reserves 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 in India and United Kingdom and is therefore exposed to foreign exchange risk against Indian rupees and UK sterling.

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, in the future 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. Although oil prices may fluctuate widely, it is the Group's present policy not to hedge crude oil sales.

Risk management

The Board has 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 2012 were identified;

·; Strategic risk - Overdependence on a single partner and lack of control to drive value creating activities; asset portfolio over-weighted to long-cycle exploration licences

·; Financial risk - A prolonged shut-in of the PY-3 field will have an impact on the Company's ability to generate cash flow; relinquishment of assets may result in an impairment provision; liquidated damages for incomplete minimum work programmes; absence of GOI budget approval may hinder recovery of auxiliary costs associated with PY-3 shut-in period; CY-OS/2 arbitration ruling not in our favour may result in an impairment provision

·; Operational risk - Dependence on a single producing asset; limited life of PY-3 field in absence of further development; sustained sub-commercial exploration results; staff retention

·; Compliance - Deteriorating stakeholder sentiment; changing regulatory and political environment in India

EMPHASIS OF MATTER

As in previous years, the board notes that within the auditors have provided an emphasis of matter comment in their audit report, which is not qualified, 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 and they continued through 2011.

The Group holds a 75 per cent participating interest in the block CY-OS/2 which is offshore the south east coast of India. Intangible assets - exploration include an amount capitalised of $51,023,493 in respect of 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. The Directorate General of Hydrocarbons ('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 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.

Consolidated Statement of Comprehensive Income

For the year ended 31 December 2011

Consolidated Statement of Changes in Equity

For the year ended 31 December 2011

The change in accounting policy is presented in Note 1d)

Consolidated Statement of Financial Position

As at 31 December 2011

Approved and authorised for issue by the Board of Directors on 6 March 2012

Consolidated Statement of Cash Flows

For the year ended 31 December 2011

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'). The domicile, country of incorporation, address of the registered office and a description of the Group's principal activities can be found in the director's report.

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 from the date of this financial statement.

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:

Issued but not yet EU adopted

IFRS 1- Amendments severe hype inflation and removal of fixed dates for first time adoption.

IFRS 9- Financial instruments

IFRS 10- Consolidated Financial Statements

IFRS 11- Joint Arrangements

IFRS 12- Disclosure of Interests in other entities

IFRS 13- Fair value measurement

IAS 1- (amended) - Presentation of items of other comprehensive income

IAS 12- (amended) - Deferred tax: Recovery of underlying Assets

IAS 19- (amended) - Employee Benefits

IAS 27- Separate Financial Statements

IAS 28- Investments in Associates and Joint Ventures

IFRIC 20- Stripping costs in the production Phase of a surface mine

Issued and EU adopted

IFRS 7 (amended)- Financial instruments disclosures

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) Change in accounting policies

Hardy was following the full cost method of accounting for its oil and gas assets wherein all expenditures incurred in connection with and directly attributable to the acquisition, exploration and appraisal of oil and gas assets were accumulated and capitalised in its India cost pool.

Hardy has elected to change to a successful efforts based accounting policy for its oil and gas assets with retrospective effect. Hardy believes this will align its accounting policy with its international peers and provide a better reflection of the results of its activities as well as its financial position.

The effect of change in this policy is writing off the cost of the unsuccessful wells capitalised in the books since inception and the associated cost of geological and geophysical activities. In addition, the depletion of property, plant and equipment-development/ producing assets were charged by considering the future cost of development with the associated proved and probable reserves under the unit of production method.

The cumulative costs of exploration dry wells and the related costs charged up to the year 2009 is US$ 50,663,569, the costs charged for 2010 is US$ 1,827,418 and the costs charged for 2011 is US$ 3,432,734.

The change in computing the depletion and decommissioning charges without considering the future costs and the associated recoverable reserves for the period up to Dec 2009 is US$ 24,785,043 and cost for the year 2010 is US$ 3,311,744. The depletion and decommissioning charges for the year 2011 is US$ 1,587,531.

The effects of change in this policy for the subsequent years are not possible to predict and therefore no quantification is made.

The effect of change in the accounting policy reduces the total carrying value of Intangible Assets- Exploration by US$ 55,923,721.

The change in the method for computing the depletion impacted a reduction in the profit for 2011 by US$ 125,669 (US$ 289,409 - 2010) and increased the profit by US$ 975,410 for the period up to 2009.

Accordingly, the corresponding amount charged to the Statement of Comprehensive Income for the year 2011 is US$ 3,558,403 and for the year 2010 is US$ 2,116,827 and the amount adjusted in the retaining earning for the period up to 2009 after adjusting deferred tax impact is US$ 35,775,474.

e) 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.

f) 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.

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.

g) 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 recognised when crude oil has been lifted and title has been passed to the buyer or when services are rendered.

h) Joint ventures

The Group participates in several unincorporated joint ventures which involve the joint control of assets used in the Group's oil and gas exploration and producing activities. The Group accounts for its share of assets, liabilities, income and expenditure of joint ventures in the statement of financial position and statement of comprehensive income as appropriate.

i) Oil and gas assets

i) Exploration and evaluation assets

Hardy has adopted the successful efforts based accounting policy for its oil and gas assets.

Costs incurred prior to acquiring the legal rights to explore an area are expensed immediately in the income statement.

Expenditures incurred in connection with and directly attributable to the acquisition, exploration and appraisal of oil and gas assets are capitalised for each license granted under the production sharing contracts and are un-depleted within intangible exploration assets until the validity to explore the contract area is ended or commercial reserves have been discovered.

Exploration expenditure incurred for geological and geophysical activities before the commencement of exploratory drilling is initially capitalised within intangible exploration assets. Exploration drilling costs are initially capitalised on a well by well basis until the success or otherwise of the well has been established. The success or failure is assessed on a well by well basis. Exploration well costs are written-off on completion of the well unless the results indicate the presence of hydrocarbon which has reasonable commercial potential.

Following appraisal of successful exploration, if commercial reserves are established and technical feasibility for extraction is demonstrated, the related capitalised intangible exploration and appraisal costs are transferred into a cost centre within the Property Plant and Equipment - development assets after testing for impairment, if any. Where exploration well results indicate the presence of hydrocarbon which are ultimately not considered commercially viable, all related costs will be written-off to the income statement.

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 the 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 capitalised.

iii) Decommissioning

At the end of the producing life of a field, costs are incurred in removing and decommissioning facilities, plugging and abandoning wells. The full discounted cost of decommissioning costs are estimated and considered as an asset and liability when the liability arises. The decommissioning cost is included within the cost of property, plant and equipment- development assets. If any revision in the estimated cost of decommissioning which alters the provisions required also adjusted in the cost of asset. The amortisation of the asset, calculated on a unit of production basis based on proved reserves, is shown as "Decommissioning charge" in the statement of comprehensive income and unwinding of the discount on the provision is included in the finance costs.

iv) Disposal of assets

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

j) Depletion and impairment

i) Depletion

The net book values of the producing assets is depreciated on a field by field basis using the unit of production method, based on proved and probable reserves. 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 following the guidance in IFRS-6 Exploration and Evaluation of Mineral Resources, 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 recognised 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 than the associated discounted future cash flows, the excess amount is recognised in the statement of comprehensive income as impairment and deducted from the pool value.

k) 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:

l) Intangible assets

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

m) Investments

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

n) 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 recognised in the statement of comprehensive income.

o) 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.

p) Financial instruments

Financial assets and financial liabilities are recognised 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.

q) Equity

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

r) 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.

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 recognised for all taxable temporary differences and deferred tax assets are recognised to the extent that it is probable that taxable profits will be available against which deductible temporary differences can be utilised.

Deferred income tax liabilities are recognised 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 recognised 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 .

s) 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 / realisations and from the year end restatement are reflected in the statement of comprehensive income.

Rates of exchanges are as follows:

t) 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.

u) 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. Critical accounting estimates and judgments

Estimates and judgements 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 will, by definition, seldom equal 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 next financial year are addressed below.

(i) Intangible assets - exploration

The Group holds a 75 per cent participating interest in the block CY-OS/2 off the east coast of India. Intangible assets include an amount of US$51,023,493 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. The Government of India ('GOI') has been requested to extend the block for appraisal and declaration of commerciality for its gas discovery for a period of 5 years from the date of discovery. This request was declined. The Production Sharing Contract ('PSC') provides for a period of 60 months from the date of discovery for declaration of commerciality in case of a discovery being Non-Associated Natural Gas ('NANG'). This period will be limited to 24 months for an oil discovery.

The Group has obtained third party legal and technical opinions that support the Group's view that the discovery is NANG and has referred the dispute to arbitration for adjudication. The Group believes that it will be successful in obtaining the extension of its licence in block CY-OS/2 in the arbitration. Therefore, the intangible assets arising from expenditure on this block continue to be recognised in full and the Directors do not believe that any impairment of these costs has arisen.

The arbitration process is continuing as at the date of approval of these financial statements.

(ii) Decommissioning

The liability for decommissioning is updated to the current cost estimates of decommissioning. Accordingly, the provision made in the books will reflect the risk free discounted future cost for decommissioning and this is an annual adjustment based on the changes in costs as a result of technical advancements and other factors. A 5 per cent change in the liability for decommissioning will impact the decommissioning charge by US$ 48,729. A 5 per cent change in proven developed reserves will impact the decommissioning charge by US$ 55,568.

(iii) Depletion

Depletion is based on best estimates of commercial reserves existing as at the year end 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. A 5 per cent change in proven developed reserves will impact the depletion charge by US$ 65,827.

3. Segment analysis

The Group is organised 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. and Hardy Oil and Gas plc operates in the United Kingdom.

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.

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 in the year 2010.

4. Cost of sales

Production cost included in the cost of sales consists of:

5. Operating loss

Operating loss is stated after charging:

The provision for potentially irrecoverable costs relates to the costs potentially irrecoverable from the parties to a production sharing contract for which budget approval is pending from the concerned parties. This provision is contained in administrative costs.

The Group has a policy in place for the award of non audit services to be provided by the auditors, which requires approval of the audit committee.

6. Reconciliation of operating profit of continuing operations to operating cash flows

7. Staff costs

Staff costs include executive Directors' salaries, fees, benefits and shares based payments and are shown gross before amounts recharged to joint ventures.

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

8. Share based payments

Share options had been granted to subscribe for the ordinary shares of US$0.01 each in the capital of the Company ('Ordinary Shares'), which are exercisable between 2010 and 2021 at prices of £ 1.44 to £ 7.69 per Ordinary Share.

Hardy has an unapproved share option scheme for the Directors and employees of the Group. Options are exercisable at the quoted market price of the Company's shares on the date of grant. The vesting period is three years with a stipulation that the options are granted in proportion to the period of employment after the grant subject to a minimum of one year and with respect to 2010 options, the period is three years. The options are exercisable for a period of ten years from the date of grant.

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

The aggregate of the estimated fair values of the options granted outstanding as at 31 December 2011 is US$ 5,812,019. The inputs into the binomial model for computation of value of options are as follows:

Expected volatility was determined by calculating Hardy's historical volatility. The expected life used has been adjusted based on management's best estimate for the effects of non-transferability, exercise restrictions and behavioural considerations. Details of outstanding options at the end of the year with the weighted average exercise (WAEP) price are as follows:

On 24 October 2008, the Company issued 20,182 Ordinary Shares having a face value of US$0.01 per share and an aggregate market value of US$80,203 (£ 50,000) to Mr Ian Bruce upon his appointment as a Non-Executive Director. The cost of issuing such shares is charged to the statement of comprehensive income over a three year period from the date of issue. In 2011 the balance, an outstanding amount of US$ 22,279 has been expensed as a share based payment.

The Group has reversed a net amount of US$ 1,269,420 in the current year and reversed an amount of US$ 961,287 in 2010 towards equity settled share based payments. Equity shares to be issued are revalued at the exchange rate as at 31 December 2011. The revaluation (loss) gain for the year 2011 is US$ (411,475) (2010: US$ 63,950). The value of shares to be issued as at 31 December 2011 is US$ 4,256,526 (2010: US$ 5,596,421).

10. Interest and investment income

11. Finance costs

12. Taxation

a. Analysis of taxation (credit) for the year

Deferred tax analysis:

b) Factors affecting tax charge for the year

Indian operations of the Group are subject to a tax rate of 42.23 percent which is higher than UK and US corporations tax rates. To the extent that the Indian profits are taxable in the US and / or the UK, 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, though the timing of related tax relief is uncertain.

13. Loss per share

Loss per share is calculated on a loss of US$ 1,877,954 for the year 2011 (2010: US$ 236,847) on a weighted average of 72,531,961 Ordinary Shares for the year 2011 (2010: 68,597,410). No diluted loss per share is calculated.

Comprehensive (loss) per share are calculated on a loss of US$ 1,877,954 for the year 2011 (2010: US$ 1,023,201) on a weighted average of 72,531,961 Ordinary Shares for the year 2011 (2010: 68,597,410).

No diluted loss per share on loss attributable to parent company for the year 2011 and 2010 are calculated.

14. 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.

The reduction in additions represents an adjustment to previous estimates made.

15. Intangible assets - exploration

The Group holds a 75 per cent participating interest in the block CY-OS/2 off the east coast of India. Intangible assets include an amount of US$51,023,493 with respect to exploration expenditures on the block 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 for a period of 5 years from the date of discovery to declare commerciality. The GOI have declined this request.

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 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 capitalised expenditure will be subject to impairment testing.

Intangible assets - exploration also includes an amount of US$ 21,435,551 in respect of Block KG-DWN-2003/1(D3).

16. Intangible assets - others

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

17. 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.

18. Inventories

19. Trade and other receivables

20. 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.

21. Share Capital

Ordinary Shares issued have equal voting and other rights with no guarantee to dividend or other payments.

23. Provision for decommissioning

The provision has been made by estimating the decommissioning cost at current prices using existing technology. The inflation and discount rates applied have been based on suitable current market information. Decommissioning costs are expected to be incurred between 2018 and 2020. 

The calculation of the provision has been changed to apply a discounted method. This change in the method of calculation is deemed to be a change of accounting estimate and is applied prospectively from the year ended 31 December 2011.

It is anticipated that the effect of the change in accounting estimate will be neutral over future periods to the anticipated date of decommissioning.

An amount of Rs.198,984,770 (US$ 3,737,505) has been deposited with State Bank of India for site restoration obligations. This amount has been treated as a non-current asset as the deposit has end use restriction for site restoration.

24. Trade and other payables

Trade and other payables are unsecured, payable on demand and are outstanding for a period of less than 12 months. Trade payables, other payables and accruals are all expected to be settled within normal credit terms.

26. Financial instruments

Book values and fair values of Hardy's financial assets and liabilities are as follows:

Financial assets

Financial liabilities

All of the above financial assets and liabilities are current at the year-end dates.

30. Contingent liabilities

Bank guarantees for US$ 1,857,150 have been issued to the Government of India. The guarantees were obtained by placing a fixed deposit of Rs.40,499,480 (US$ 760,696) with a bank with the interest rate of 9 per cent.

The Group issues guarantees in respect of obligations under various production sharing contracts ('PSC') in the normal course of business. The Group has provided guarantees of US$ 1,857,150 as at 31 December 2011 issued under a facility with a bank for the Group's share of minimum work programme commitments for the year to 31 March 2012. The details of the bank guarantees provided are as follows:

In addition, the parent company guarantees the Group's obligations under various PSC's to the Government of India.

The guarantees are deemed to have negligible fair value and are therefore accounted for as contingent liabilities.

31. Related party transactions

The aggregate remuneration of Directors and the key management personnel of the Group is as follows.

Further information about the remuneration of individual Directors is provided in the Directors' Remuneration Report which forms part of the Group's 2011 Annual Report.

RESERVES AND RESOURCES

The Company had previously committed to commission the updating of a competent person's report (CPR) on an annual basis in conjunction with the year-end financial reporting process. Due to limited drilling activity in 2011 and the uncertainty surrounding the recommencement of production in the PY-3 asset, the Company took the decision to postpone the updating of a competent person's report until later in the year. The estimates provided in the Company's 2010 CPR are provided below.

Reserves (Proven Plus Probable)

Net PY-3 oil production from 31 December 2010 to 31 December 2011 was 129 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 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 are 174 BCF.

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

D9 - The exploration phase of the block is complete and the joint venture has until July 2012 to submit an appraisal programme for the KG-D9-A2 natural gas discovery. In the absence of the submission the block will stand relinquished.

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