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Preliminary Results

4 Mar 2010 07:02

RNS Number : 0620I

Hardy Oil & Gas plc

04 March 2010

Immediate Release 4 March 2010

Hardy Oil and Gas plc

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

Preliminary Results

for the year ended 31 December 2009

Hardy Oil and Gas plc (LSE : HDY), the oil and gas exploration and production company with interests predominantly in India, today announces its Preliminary Results for the year ended 31 December 2009.

*All financial amounts in US dollars unless otherwise stated.

Operational Highlights

·; D3: Drilled the third consecutive gas discovery on the D3 block (Dhirubhai 44)

·; D3: Appraisal programme for Dhirubhai 39 and 41 discoveries was submitted to DGH for review

·; D3: Completed the acquisition of 1,150 km2 of 3D seismic data (3D seismic data has now been acquired across the entire block)

·; D9: Drilled the first of four exploration wells on the D9 block, which was plugged and abandoned

·; Assam: Completed the acquisition of 390 line km of 2D seismic data

·; PY-3: Hardy's net entitlement average daily production for 2009 was 276 stbd (2008: 397 stbd)

·; PY-3 field was suspended in July 2009 and re-commenced production in January 2010 at an initial stabilised rate of 3,336 stbd

·; PY-3: The PY3-PD4-RL well was suspended with a gas lift valve in position for future reactivation with artificial lift

Financial Highlights

·; Loss before taxation of $7.9 million (2008: profit before taxation $12.4 million*)

·; Cash deficiency from operations of $4.1 million† (2008: Cash surplus $1.6 million†)

·; Capital expenditure of $13.5 million (2008: $31.6 million)

·; Equity issue in April 2009 raising net proceeds of $15.2 million

·; Cash and short-term investments at 31 December 2009 of $30.5 million (2008: $30.1 million) and no long-term debt

* Including gain of $13 million from sale of investment

† Before changes in non-cash working capital

Management

·; Chief Executive Sastry Karra becomes Non Executive Director and Yogeshwar Sharma succeeds Mr Karra as Chief Executive Officer effective 31 March 2010

Outlook

Exploration

·; D3: Commencement of drilling the fourth exploration well on the D3 block expected in the first half of 2010; a further two exploration wells by the end of the year

·; D9: The re-commencement of exploration drilling in the second half of 2010

Appraisal

·; D3: The D3 joint venture is considering the drilling of at least one appraisal well in the second half of 2010

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

"Our existing exploration portfolio in the Krishna Godavari Basin and other India basins offer significant organic growth potential for the Company. The Company is planning the drilling of a further five exploration wells by the end of the first half of 2011 and we look forward to executing this programme."

For further information please contact:

Hardy Oil and Gas plc 020 7471 9850

Sastry Karra (Chief Executive)

Yogeshwar Sharma (Chief Operating Officer)

Dinesh Dattani (Finance Director)

Arden Partners plc 020 7614 5917

Richard Day

Matthew Armitt

Buchanan Communications 020 7466 5000

Mark Edwards

Ben Romney

Chairman's Statement

Corporate Overview

2009 was an important year for Hardy as we continued our exploration programme on the Company's portfolio in the Krishna Godavari Basin. As a result of our activity, we were delighted to announce the third consecutive gas discovery in the D3 block. We also began our four well exploration drilling campaign in the D9 block. The first well was plugged and abandoned and the data is currently being integrated into the D9 geological model to optimise selection of future drilling locations. Despite challenging market conditions, the Company was successful in raising $15 million in equity through a placing in 2009. The placing is testimony to the significant growth potential our asset portfolio offers and highlights the continued support of our core shareholder base.

India remains a rapid growth story and the demand for energy continues to be robust, mirroring the country's significant economic growth. Hardy has a clear objective of creating significant shareholder value through an India focused exploration and development strategy.

Our India focused strategy has produced five gas discoveries from nine exploration wells over the past three years. We expect to drill a further five exploration wells by the end of the first half of 2011 and we continue to believe that our existing exploration portfolio in the Krishna Godavari Basin and other India basins offers significant organic growth potential for the Company.

Key Results

As a result of the reduction in global oil prices and an extended shut-in of our PY-3 field, the Company recorded a 56 per cent reduction in gross revenue and as a result Hardy recorded a net loss of $6.5 million compared to net income of $7.5 million in 2008. Net income for 2008 included an after tax gain on investment of $8.9 million. The Company's fully diluted loss per share was $0.10 compared to fully diluted earnings per share of $0.11 in 2008.

The Company's capital expenditure amounted to $13.6 million which was principally on the drilling of one development well, two exploration wells, the acquisition of seismic data and the pre-drilling of a well on D3. The Company ended 2009 with $30.5 million in cash and short-term investments and no long-term debt.

Management Change

As announced today, Sastry Karra will be relinquishing his current position as Chief Executive and maintain an ongoing involvement with the Company as a Non Executive Director. Yogeshwar Sharma, currently Chief Operating Officer, will succeed Sastry Karra as Chief Executive Officer effective 31 March 2010.

We would like to thank Sastry for his tireless work over the past 12 years as Chief Executive. It was Sastry's vision that has placed Hardy in the position it is today. The management is determined to fulfil the potential of that vision.

Governance

Following an appraisal of the Board and its members in 2009, the Board considers that its current structure, competencies and remuneration policies are appropriate for a publicly listed, early stage, oil and gas exploration company. As such we did not undertake any material changes in 2009. We will continue to periodically review the appropriateness of the Board composition, structure and internal processes as the Company evolves.

Risk Management

Risk management will continue to be a key focus of the Board in 2010. Given the Company's objective of creating significant shareholder value, we have chosen an exploration focused strategy. Exploration is intrinsically very uncertain and whilst substantial improvements in predictive/interpretation technology have reduced this uncertainty, it can not be eliminated.

Despite the global downturn, demand for upstream oil and gas equipment has remained robust and we continue to operate in a relatively high-cost environment which magnifies the financial impact of operational delays during drilling and other operations.

A number of our exploration licences are being held under appraisal and our continued interest in such blocks are contingent on establishing commerciality. A decision on the commerciality of Dhirubhai 33 gas discovery (GS-01) is anticipated this year.

With respect to Hardy's Ganesha (CY-OS/2) non-associated natural gas discovery, the Company has presented a case to the Directorate General of Hydrocarbons that supports our claim of entitlement to a licence extension. In the absence of a resolution in our favour in the near future, we intend to refer the dispute for sole expert or conciliation and arbitration.

Year End Audit

The auditors have substantially completed their work in connection with the 2009 financial year and are expected to provide an unqualified audit opinion on the 2009 financial statements. The auditors are expected to provide an emphasis of matter comment in their audit report with reference to the uncertainty concerning the Group's request for an extension of its exploration licence in block CY-OS/2 as disclosed in notes 2 and 9 to the financial statements.

Outlook

We continue to strive to create significant shareholder value by focusing on high impact exploration in India. The year 2010 should prove to be crucial in the realisation of our vision for Hardy. We expect to drill five further exploration wells in the Krishna Godavari Basin by the end of the first half of 2011, which will complete the phase one minimum work programmes for the D3 and D9 exploration blocks.

D3: Exploration drilling on the D3 block is expected to re-commence in the second quarter of 2010. The D3 block is not operated by Hardy and at this time the schedule of further exploration and appraisal drilling on the block is dependent on a number of issues outside of the control of the Company.

D9: The Company anticipates the re-commencement of exploration drilling on D9 in the second half of 2010 upon completion of ongoing geological studies to incorporate data gathered from the KG-D9-A1 well. We anticipate providing an update of the prospect portfolio of this block prior to the re-commencement of drilling.

PY-3: The PY-3 joint venture is working towards finalising and approving further drilling to increase production and enhance ultimate recovery. The drilling portion of this programme is currently envisioned to start in first half of 2011.

CY-OS/2 and GS-01: The drilling of an appraisal well on the CY-OS/2 block is dependent on the outcome of our request for an extension to the CY-OS/2 licence. The GS-01 joint venture will continue various geological and geophysical studies to determine the commerciality of the Dhirubhai 33 gas discovery.

Assam: The joint venture will continue the prospect development process with the processing and interpretation of acquired seismic data. Drilling will be dependent on identifying material prospects. However, we expect a drilling programme to be initiated in phase two, which commences in the first quarter of 2011.

Nigeria: The Company will provide technical assistance to the operators of the Oza and Atala fields to facilitate the realisation of value.

Given the substantial amount of new data acquired in 2009, the Company intends to publish an update to its past competent person and technical evaluation reports, on all of its assets, by the end of the first half.

Corporate

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

The Board remains committed to its India focused strategy. In the near term, Hardy's Krishna Godavari Basin assets remain the primary focus of our exploration programme. The recent D3 Dhirubhai 44 gas discovery in the Miocene has proven a substantial geological fairway. We view D3 with considerable optimism and believe that 2010 will be an important year in Hardy's development. We remain optimistic about the potential of D9 and look forward to re-commencing the exploration drilling programme. The Company is well positioned to see itself through its key exploration activities in 2010.

E.P. Mortimer

Chairman

3 March 2010

Chief Executive's Statement

With an active exploration drilling programme and adequate cash reserves, the year 2010 should provide the Company with an enhanced understanding of the geology of the Krishna Godavari Basin and clarity on the future resource potential of Hardy's promising D3 and D9 exploration blocks.

Execution of Strategy

The Company remains committed to its India focused strategy with a mandate of creating significant long-term shareholder value through the exploration and appraisal of our existing exploration portfolio. With the unprecedented volatility of the global economic landscape and mixed results from our exploration and development drilling, 2009 proved to be a challenging year on several fronts.

Given India's robust economic growth projections and attractive upstream fiscal and regulatory regime, the Company continues to view India as an excellent investment opportunity for upstream oil and gas activity. In 2010, we will focus on maintaining key relationships and enhancing our regional technical and operational expertise.

Exploration Highlights

The highlight of our 2009 exploration programme was the drilling of two deep water wells on the Company's Krishna Godavari Basin blocks. The third successive discovery on our D3 block has re-enforced our expectations for this block and we anticipate the completion of the phase one exploration drilling programme, and the advancement of a comprehensive appraisal programme for the existing discoveries Dhirubhai 39, 41 and 44, in 2010.

The first well on the Company's D9 block (KG-D9-A1) did not provide the anticipated results. In conjunction with the operator, we are currently incorporating the data from this well to refine the next three exploration well locations on this block. We expect to provide an updated geological assessment of this block prior to the re-commencement of the drilling programme.

In 2009, Hardy completed two seismic acquisition programmes: 1,150 km2 of 3D seismic data was acquired over the north east portion of the D3 block and 390 line km of 2D seismic data was acquired over the onshore Assam block. With the acquisition on D3, the Company now has 3D seismic coverage over the entire D3 concession.

The Company continued to work with the Ministry of Petroleum and Natural Gas and Directorate General of Hydrocarbons (DGH) to confirm an extension of the CY-OS/2 block prior to commencement of the appraisal programme for Hardy's Ganesha non-associated natural gas discovery. In the absence of a resolution in our favour, in the near future, we intend to refer the dispute for sole expert or conciliation and arbitration.

Appraisal of the Dhirubhai 33 discovery (GS-01) continued in 2010 with further geological and geophysical studies.

Resource Potential

In May 2009, Hardy released the Company's prospective resource potential as evaluated by Gaffney Cline & Associates Ltd for the two KG Basin blocks, D3 and D9. Of particular note was the play fairway analysis undertaken which highlighted the significant resource potential of the D3 block (risked prospective natural gas resource of 9.6 TCF). This estimate was completed prior to the drilling of the KG-D3-R1 discovery.

The Company intends to publish an updated technical evaluation, on all of its assets, by the end of the first half of 2010.

Development and Production

During 2009, the Company's oil production was 0.56 MMstb compared with 0.93 MMstb for 2008. The reduction was a result of a six month, unplanned, shut-in of the PY-3 field. The field re-commenced production in January 2010 at an initial gross rate of 3,336 stbd. For 2010, the PY-3 field is forecast to produce at an average rate of 3,000 stbd.

The drilling of an additional lateral well, via the re-entry of the producing PY-3-PD4 well was completed in February 2009. With the assistance of a nitrogen lift, the well flowed at 700 stbd of oil with 30 per cent water-cut. However, the well could not be reactivated as a self flowing well. The well has been completed and suspended with a gas lift valve to allow for future oil production when gas lift compression facilities are installed on the floating-point unit (FPU).

In 2009, the joint venture negotiated a one year contract extension to the PY-3 production facilities effective 24 January 2010, at a 40 per cent reduction in day rate.

PY-3 joint venture partner approval to drill two more production wells is expected in the first half of 2010 with drilling to take place in the first half of 2011.

Financial Highlights

Revenue was down from $17.3 million in 2008 to $7.7 million in 2009 principally due to an unplanned extended shut-in of the PY-3 field. Administrative expenses were down by 9 per cent compared to 2008, resulting in an operating loss of $8.1 million in 2009 compared with an operating loss of $1.7 million in 2008.

The Company started 2009 with cash reserves of $30.0 million. Net cash used in operating activities was $1.0 million. Cash used for investing activities amounted to $13.5 million in 2010 for the drilling of PY3-PD4-RL, KGV-D3-S1, KGV-D3-G1, KG-D9-A1 wells and additional seismic on the D3 and Assam exploration blocks. An equity issue in April 2009 resulted in net proceeds of $15.4 million augmenting our working capital. As a result, the Company's cash reserves at the end of 2009 were $30.5 million. The Company remains in a positive financial position and has no long-term debt.

Key Partnerships

Hardy continued to work closely with strategic partners in India. The Company interacts on a regular basis with its partners at multiple levels, to ensure that our goals and objectives are addressed and to facilitate planning of upcoming work programme schedules. Maintaining open and substantive relationships with existing partners and other key stakeholders in the India upstream oil and gas sector are critical to the execution of the Company's strategy.

2010 Programme

As mentioned earlier, the third successive discovery on our D3 block has enhanced expectations as we anticipate the completion of the phase one exploration drilling programme through the drilling of three further exploration wells. The next location on this block is expected to be the KGV-D3-W1 exploration well, targeting several high amplitude anomalies in the Pliocene and Miocene geological horizons. The well is approximately 20 km south east of the Dhirubhai 39 and 41 discoveries. We expect the drilling to commence by the end of the second quarter of 2010.

The timing of re-commencement of the D9 three well exploration drilling programme will be subject to the completion of ongoing data analysis and updating of the geological model. We anticipate drilling to commence in the second half of 2010 and continue into 2011.

We are enthusiastic about the balance of 2010, as we continue our efforts to de-risk our exploration portfolio in the Krishna Godavari Basin in India through further exploration drilling. Our disciplined capital allocation strategy will deliver activities that have the potential to result in a significant increase in shareholder value. Beyond the Company's existing portfolio, the Company will continue to evaluate and assess potential acquisitions in India via its New Exploration Licence Policy (NELP) bidding rounds and other conventional means that offer material value creation opportunities that will complement our existing assets and organisational competencies.

Staff

2009 was a challenging year for the Company and we would not have been able to see it through without the dedication of our staff in India, Nigeria and the United Kingdom. Our India team continues to drive the core of our business and we will look to continue to retain and enhance our technical, operational and management expertise in this region. In 2010 we look to our staff to perform at a high level in the execution of our 2010 work plan and beyond. I would like to take this opportunity to acknowledge their important contributions in the past year.

Sastry Karra

Chief Executive

3 March 2010

Financial Review

During 2009, the Company had an unplanned extended shut-in of the PY-3 field which had a significant impact on its financial performance. The absence of production in the second half of 2009 and lower oil prices resulted in a substantial reduction in revenue. As a result, the Company has recorded a loss for 2009. In April 2009, the Company successfully placed 6,208,997 Ordinary Shares for net proceeds of $15.2 million. Hardy completed the year with cash and short-term investments of approximately $30.5 million and no long-term debt.

Key Performance Indicators

	Year ended 31 December
	2009	2008
Production (barrels of oil per day - net entitlement basis)	276	397

Average realised price per barrel $	52.96	104.44
Average cost per barrel $	49.61	54.91

Revenue (thousands of $)	7,687	17,306
Net (loss) profit (thousands of $)	(6,517)	7,472
Cash flow from operations* (thousands of $)	(4,117)	1,648

Diluted (loss) earnings per share $	(0.10)	0.11
Wells drilled	2	4

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

Operating Results

	Year ended 31 December
	2009	2008
Production (barrels of oil per day)
Gross field	1,535	2,542
Participating interest	276	458
Net entitlement interest	276	397

Sales (barrels of oil per day)
Gross field	2,209	2,725
Participating interest	398	491
Average realised price per barrel $	52.96	104.44

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 2009 amounted to 1,535 stbd compared with 2,542 stbd for 2008. The decrease in production is due to an unplanned six month shut-in of the field to undertake repair of the offshore facilities. Hardy profit oil payment to the Government of India (GOI) was nil in 2009 compared to $2.3 million in 2008. The Company does not anticipate the payment of profit oil to the GOI in 2010 due to substantial unrecovered costs.

Revenue from oil sales (after profit oil) decreased from $16.4 million in 2008 to $7.7 million in 2009. The average price realised per barrel decreased significantly from $104.44 during 2008 to $52.96 in 2009. Average daily sales amounted to 398 stbd compared with 491 stbd reflecting lower production volumes from the extended shut-in and partially offset by the sale of inventory during the year.

Cost of Sales

Cost of sales for 2009 decreased from $9.2 million in 2008 to $5.7 million in 2009. This reflects the fact that lease charges for the production and storage facilities were not incurred during the PY-3 field shut-in period. The contract for the floating processing and storage systems has been renegotiated effective January 2010 for a period of one year at a substantially reduced day rate.

Gross Profit

Gross profit decreased from $8.1 million in 2008 to $0.8 million in 2009. The decrease arises principally from lower revenues as a result of a significant reduction in oil sales and significantly lower average crude oil price in 2009.

Administrative Expenses

Administrative expenses decreased from $9.8 million in 2008 to $9.0 million in 2009. The decrease principally results from exchange gains of $0.7 million in 2009 compared with an exchange loss of $1.3 million recorded in 2008, offset by additional costs associated with the drilling of PY3-PD4-RL well in early 2009 of $1.0 million.

Operating Loss

The Company is reporting an operating loss of $8.1 million in 2009 compared with $1.7 million in 2008. The increase in loss principally results from the shut-down of the PY-3 in the last half of 2009 coupled with lower oil prices.

Interest and Investment Income

Investment and other income in 2009 amounted to $0.3 million compared with $1.3 million in 2008. The decline is primarily attributable to significantly lower interest rates obtained on cash and short-term investments in 2009 compared to 2008. The lower realised interest rates are systematic with unprecedented reductions in UK and US central bank rates.

Finance Costs

Finance costs principally include the cost of providing bank guarantees to the GOI required by the provisions of production sharing contracts and are based on the agreed annual work programme on blocks in India.

Loss Before Taxation

The Company recorded a loss before taxation of $7.9 million compared to a profit before taxation of $12.4 million in 2008. During 2008, the Company recorded a realised pre-tax gain on investment of $12.9 million arising on the liquidation of its holding in Hindustan Oil Exploration Company Limited (HOEC).

Taxation

During 2009, the Company did not incur any current tax liability as a result of losses. During 2008, the Company's current tax liability was $1.6 million comprising of $0.8 million in connection with minimum alternate tax in India and tax on short-term capital gains of $0.8 million on sale of investments in India.

Tax relief, as a percentage of pre-tax loss amounted to 17.9 per cent in 2009 compared to a tax charge of 39.9 per cent in 2008. The lower rate for tax relief results from no tax relief reflected for Nigeria losses, and the impact of the non-deductibility of a substantial part of share-based payments. The higher rate reflected in 2008 resulted from the above factors as well as current tax on short-term capital gains of $0.8 million on investment gain.

Net Profit

Net profit declined from $7.5 million in 2008 to a net loss of $6.5 million in 2009.

Cash Flow from Operating Activities

The Company's cash flow used in operating activities, before changes in non-cash working capital, amounted to $4.1 million in 2009. This compares with cash flow from operations of $1.6 million for 2008. The decline principally results from reduced oil sales volumes and related prices in 2009 compared to 2008.

Capital Expenditure

Capital expenditure amounted to $13.6 million during 2009, compared to $31.7 million incurred during 2008. Capital expenditure amounting to $2.9 million was incurred on the PY-3 block with the drilling of PY3-PD4-RL. Approximately $5.2 million was incurred in the drilling of two exploration wells, pre-drilling of one well, and a 3D seismic programme on the D3 block in the Krishna Godavari basin. Approximately $3.6 million of expenditures are attributable to the drilling of one well on the D9 block. As part of the Dhirubhai 31 (GS-01) appraisal programme, the Company incurred $0.4 million on the GS-01 block, on a number of geological and geophysical studies including reprocessing of the 3D seismic data covering the block. In addition, $1.2 million was spent on the acquisition of 2D seismic on the Company's onshore Assam block.

Site Restoration Deposit

This represents the deposit for site restoration for future site restoration expenses for the PY-3 field. In 2009, the Company increased the site restoration deposit by $0.4 million to $3.4 million.

Cash and Short-term Investments

The Company's cash and short-term investments remained essentially unchanged at $30.5 million at the end of 2009. The Company's capital expenditures were principally funded by proceeds from a placing during 2009. At the end of 2009, the Company placed $19.9 million and $0.6 million in US dollar and Sterling liquidity funds at HSBC with average underlying maturity of 43 days and 34 days respectively. The Company does not have any long-term debt.

Summary Balance Sheet

Hardy's non-current assets have increased from $135.8 million at the end of 2008 to $148.4 million at the end of 2009. This resulted largely from the exploration and development capital expenditure programme, principally the drilling of wells and seismic acquisition on PY-3, D3, D9, GS-01 and Assam blocks. Current assets represent the Group's cash and short-term investments, trade and other receivables and inventory. At the end of 2009, of the $36.8 million of current assets, $30.5 million are represented by cash and short-term investments.

Current liabilities are principally trade and other accounts payable. The level of current liabilities is $15.4 million at the end of 2009 compared with $13.8 million in 2008, reflecting the impact of the drilling operations on the KGV-D3-R1 well on the D3 block that finished in the last weeks of 2009.

During 2009, the Company issued $15.2 million of equity principally due to a placing. Consequently, the Company's net assets increased to $155.5 million at the end of 2009 from $144.2 million at the end of 2008.

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.

Dividends

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

Risk Factors

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

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

A summary of the principal risks facing the Company and the way in which these risks are mitigated is provided in this report.

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

Dinesh Dattani

Finance Director

3 March 2010

Review of Operations

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

2009 Performance

The highlight of 2009 was the KGV-D3-R1 gas discovery (Dhirubhai 44) which is the third consecutive discovery on the Company's D3 block. Overall 2009 was a challenging year for Hardy with drilling results in PY-3 and D9 coming below expectations. The Company is now working hard to incorporate the well data to optimise selection of future exploration and development drilling locations on all of the Company's blocks in India.

At the beginning of 2009 the Company planned to drill two exploration wells, one to two appraisal wells, one development well and acquire 1,150 km2 of 3D and 450 line km of 2D seismic data in India.

Through 2009, the Company has participated in the drilling of two exploration wells (KG-D9-A1 and KGV-D3-R1), pre-drilled exploration well KGV-D3-G1, drilled the PY3-PD4-RL development well and acquired 1,150 km2 of 3D seismic data on D3 and 390 line km of 2D data on the Assam exploration block.

In Nigeria, the Company had planned to commence the tie-in of the Oza field and potentially re-enter and test the Atala-1 well. The Company now plans to initiate the installation of the pipeline for the Oza field in the second half of 2010. The timing of commencement of the Atala-1 re-entry will be subject to securing the appropriate drilling equipment, which remains a challenge for a number of marginal field operators in the Niger Delta.

The table below provides a brief comparison of our stated operational objectives for 2009 and our subsequent accomplishments through the year:

Block	Projection	Execution
D3	Complete acquisition of 1,150 km2 of 3D seismic data in the toe thrust area	Completed the acquisition of 1,150 km2 of 3D seismic data
D3	Drill the third exploration well on the block	Announced the gas discovery Dhirubhai 44 (KGV-D3-R1); pre-drilled KGV-D3-G1
D9	Drill the first of four exploration wells	Drilled the KG-D9-A1 exploration well (P&A)
GS-01	Contingent appraisal well for Dhirubhai 33 gas discovery	The joint venture elected to defer the drilling of an appraisal well in 2009
Assam	Acquire 450 line km of 2D seismic data	Acquired 390 line km of 2D seismic data
PY-3	Drill development well PY3-PD4-RL	Drilled the PY3-PD4-RL (suspended)
CY-OS/2	Obtain an extension for the appraisal of Ganesha gas discovery	Ongoing discussions with the GOI
Oza	Commence field tie-in operations	Received 34 km of pipe, ROW, EIA and pipeline FEED studies ongoing
Atala	Re-enter and test Atala-1	Securing of equipment required to undertake the re-entry proved to be challenging
CPR	Publish an updated technical evaluation report on D9, D3 and Assam blocks	Published a technical evaluation report by GCA on D9, D3

Competent Person's Report Update

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

(Hardy 10 per cent interest)

2009 Operations

For the second year in a row the Company's D3 block provided the highlight of Hardy's exploration programme with the discovery of gas on the Company's D3 block (Dhirubhai 44). The primary results of operations undertaken on this block in 2009 are listed below:

KGV-D3-R1: On 22 December 2009, the Company announced a third discovery on the D3 block (Dhirubhai 44). The well KGV-D3-R1, was drilled in a water depth of 1,982 m to a total measured depth of 4,113 m. Three reservoir zones were encountered at Miocene Level having gross thicknesses of 4, 23 and 16 m. The potential of these zones were evaluated through a wire-line based technology called Reservoir Characterization Instrument (RCI). The evaluation and incorporation of the data obtained from the D3 discoveries is ongoing.

KGV-D3-G1: Hardy commenced the drilling of a fourth exploration well KGV-D3-G1. Drilling was subsequently suspended after setting of 20" casing at 1,625 m total vertical depth (TVD). The joint venture intends to re-enter the well at a later date to drill to TD @ 2,510 m sub-sea (ss) and test prospective geological horizons.

The Company acquired a further 1,150 km2 of 3D seismic data in 2009. With the completion of this programme, the joint venture now has 3D seismic data coverage over the entire block. Additional interpretation and processing was completed on previously acquired data, including PSTM, PSDM and AVO/inversion studies.

Prior to the drilling of KGV-D3-R1, the Company published a third party technical evaluation report which provides the Prospective Resource potential of the block and the geological chance of success of various prospects. Play-based exploration methodology was employed to address both the current prospect inventory and the 'yet to find' resource potential of the D3 block. Using the play based exploration methodology, the potential gross risked Best Estimate Resources for the D3 block was estimated at 9.5 TCF (Effective May 2009). This includes identified prospects and leads and a number of postulated prospects based on the play-based exploration methodology and field size distribution. A summary report can be found on the Company's website www.hardyoil.com.

2010 Outlook

Exploration: The joint venture is planning for the drilling of three further exploration wells by the second quarter of 2011. The drilling of these exploration wells will meet the blocks phase one minimum work programme commitments for the block.

Appraisal of Dhirubhai 39 and 41: In 2009, the D3 joint venture Operating Committee reviewed and approved an appraisal programme for the evaluation of the Dhirubhai 39 and 41 gas discoveries. The proposed appraisal area comprises 750 km2 covering a large portion of the north west corner of the block. The appraisal programme provides for the initial undertaking of various geological, geophysical and development concept studies, following which two appraisal wells could be drilled prior to February 2011. The joint venture is planning to complete an electro magnetic (EM) survey prior to the drilling appraisal wells.

Background

The D3 block is situated in the emerging world class Krishna Godavari Basin in India, encompasses an area of 3,288 km2, is in water depths ranging from 400 m to 2,200 m, and is located approximately 45 km offshore. The block is operated by Reliance.

The minimum work programme for phase one of the licence requires the drilling of six exploration wells. To date, three exploration wells have been drilled and one well has been pre-drilled. In its technical evaluation report, GCA noted that the presence of an unconventional biogenic gas petroleum system in deepwater offshore India has been proven in the D3 block.

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

(Hardy 10 per cent interest)

2009 Operations

2009 marked the commencement of the drilling phase of the block's exploration programme. There are three play types postulated to be present in the block: structural (anticlines- northern, central and southern) strati-structural; and stratigraphic. The D9 joint venture has initially focused exploration efforts in the north west corner of the block covering an area of approximately 3,640 km2.

The first exploratory well in the D9 block, KG-D9-A1, was to evaluate the prospectivity of the Middle and Lower Miocene sands deposited in the lower slope regime in a distal toe thrust structural play in the central anticline.

Observations from A1 Well Data

• In the interval 3,235-3,242 m from rotary table (RT) from the Early Pliocene section, observed resistivity up to 30 ohms in the pilot hole where no samples could be collected.

• In the interval of 3,500-3,650 m RT of Upper Miocene age, several thin sandstone and siltstone units having thickness of 1-3 m were encountered with a total gas > 2 per cent with mostly C1 component. The maximum Resistivity of up to 3 ohm was observed in the interval 3,510-3,515 m RT with total gas of 1 per cent.

• The first target in the Middle Miocene level encountered siltstone in the interval 4,160-4,185 m RT and 4,370-4,500 m RT with low resistivities and insignificant gas shows.

• The deeper target in the Lower Miocene section encountered limestone in the interval 4,695-4,710 m RT contrary to the expected (prognosed) coarse clastic. No significant gas shows were observed in this interval.

Inference from A1 Well Results

• In the Upper Miocene, the KG-D9-A1 well encountered several thin sandstone units with good gas shows (C1 dominant) suggesting the possibly a biogenic source. Studies are being conducted to identify the likely thick reservoir prone areas based on the detailed sedimentological studies of KG-D9-A1 well cores and cuttings, and D6 block subsurface data. These reservoirs are likely to be on the flanks of anticlines in the mini-basin set up.

• In the Middle Miocene, the KG-D9-A1 well encountered siltstone with low resistivity and insignificant gas shows. This zone needs to be thoroughly re-evaluated to identify the probable reservoir entry directions.

• Tight limestone was encountered in the Lower Miocene level in the well. The data suggests this limestone package was transported from the shelf area to the north through a slope channel system. This will be confirmed by side wall core and cutting sample analysis data.

• The remaining prospectivity of all the anticlinal closures (north and central) cannot be ruled out because presence of effective reservoirs and biogenic source will make them viable targets.

• The KG-D9-A1 well drilled into the Lower Miocene section did not penetrate the Cretaceous and Palaeocene sections thus their prospectively remains unchanged.

2010 Outlook

The data obtained from the KG-D9-A1 well is currently being integrated with the existing geological model to improve the understanding of the geology and petroleum systems within the block before drilling subsequent wells. Some specific activities planned for 2010 are listed below:

• complete sedimentological and paleontological studies of the side wall cores and drill cuttings to understand the presence of limestone in the block;

• carry out inversion studies of the 3D seismic based on the new data from the A1 well and nearby D6 block data to identify the reservoirs; and

• refine the geochemical model for understanding the source rock potential.

The D9 block's exploration drilling programme is expected to re-commence in the second half of 2010.

Background

The licence encompasses 11,605 km2 in the Bay of Bengal where water depths vary from 2,300 m to 3,100 m. The joint venture has acquired over 4,188 km2 of 3D seismic data. Regarding the status of the D9 block, the operator submitted a proposal requesting the grant of a drilling moratorium for three years from January 2008 to December 2010 on the basis that the Operator has not been able to complete the minimum work obligations of exploratory drilling in view of non-availability of suitable deep water rigs in the international market. Similar proposals were also submitted by other operators including the national oil company ONGC. The D9 operator is in receipt of a letter from DGH that the blocks, inter alia, have been recommended by DGH to GOI for the grant of a drilling moratorium. The proposal is under active consideration by the GOI. Should the Drilling Moratorium not be granted, there are provisions for availing extension of the phase one period based on statutory delays and the other allowable extensions as per a DGH extension policy.

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

(Hardy 10 per cent interest)

2009 Operations

The GS-01 joint venture continued various geological and geophysical studies in relation to the appraisal of the GS01-B1 gas and condensate discovery (Dhirubhai 33). The licence is currently active under an adopted appraisal programme. The appraisal area comprises 5,890 km2 with a term through to May 2010.

2010 Outlook

A decision on the drilling of an appraisal well is expected to be made prior to the end of the first half of 2010. The joint venture is considering whether an additional well is required to declare commerciality.

Background

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

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

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

(Hardy 10 per cent interest)

2009 Operations

In 2009 the Company acquired 390 line km of 2D data. The majority of the exploration block's phase one minimum work programme has now been completed. GCA's technical evaluation report noted that they consider 'the Assam opportunity as a challenging, potentially attractive play extension and possible new play(s) opportunity with neighbouring oil discoveries in the sub-regional context'.

2010 Outlook

Further field operations will be based on the results and interpretation of the 2D data and other ongoing geological studies. Drilling will be planned with the commencement of phase two in 2011.

Background

The AS-ONN-2000/1 exploration licence is located in the north eastern state of Assam, India and north of the Brahmaputra River. The exploration licence covers an area of 5,754 km2 and falls within the districts of Darrang and Sonitpur. The block is in phase one of a three phase exploration licence. Phase one (three years) will expire in January 2011.

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

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

(Hardy 18 percent interest - Operator)

2009 Production

Gross average daily field production for the year ended 31 December 2009 was 1,535 stbd (2008: 2,550 stbd). The production facilities' uptime performance was 51.0 per cent (2008: 88.2 per cent). The decrease in production was the result of an extended shut-in to repair the field's offshore mooring facility. Adverse marine conditions compounded the time taken to finish the repairs. The field recommenced production on 24 January 2010 at a rate of 3,336 stbd.

In 2009 the joint venture extended the contract of the PY-3 field's production facility for one year up to 24 January 2011. The new contract provides for a 40 per cent reduction from the previously contracted rate.

Gross average daily production for January and February 2010 was 835 stbd and 3,450 stbd respectively. We anticipate that the PY-3 field will average gross daily production of 3,000 stbd for 2010. Currently the field is producing at a gross rate of 3,400 stbd.

2009 Operations

In February 2009, the Company completed the re-entry and drilling of an extended lateral section in the PY3-PD4-RL well. With the assistance of nitrogen lift, the well flowed at 700 stbd of oil with 30 per cent water-cut. However, the well was unable to be reactivated as a self flowing well. The well has been completed as a producer with a gas lift valve to allow for future production when gas lift compression facilities are installed on the FPU.

Hardy has subsequently revised its geological and reservoir simulation models to incorporate new data gathered from the PY3-PD4-RL well. The revised model will be used to plan future in-fill drilling and production facility requirements.

2010 Outlook

The Company expects gross daily production of the PY-3 field to average 3,000 stbd in 2010. The PY-3 field joint venture's Technical Committee has recommended the drilling of two additional lateral wells and various facility upgrades including gas compression for gas lift and sales gas. Drilling of these wells is expected to commence by the first quarter of 2011 and additional production from the wells is expected to commence in the second half of 2011.

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 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, 'Endeavor', which acts as a floating storage and offloading unit. There are four sub-sea wells tied back to Tahara. Tahara has a three-stage crude oil separation system, with the first two stages being three-phase separators and the third stage a two-phase separator.

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

Block CY-OS/2: Exploration

(Hardy 75 per cent interest - Operator)

2009 Operations

In 2009 the joint venture applied to the Ministry of Petroleum and Natural Gas of the GOI to establish commerciality of the Ganesha gas discovery during an appraisal period ending January 2012 as provided for in the production sharing contract (PSC).

On 20 February 2009 HEPI received a communication from DGH to establish commerciality within 15 days or relinquish the block. We believe that this action was taken by DGH on the assumption that the Ganesha discovery was an oil discovery. As Ganesha is a non-associated gas discovery, the CY-OS/2 PSC provides for an appraisal programme to establish commerciality by January 2012. Hardy has subsequently presented a case to the DGH that supports its claim that the CY-OS/2 joint venture is entitled to a licence extension as the result of a non-associated gas discovery. In the absence of a resolution in our favour in the near future, the group intends to refer the dispute for sole expert or conciliation and arbitration.

2010 Outlook

Should the joint venture receive confirmation of the extension period in a timely manner, Hardy will undertake the activities necessary to fully appraise the Ganesha discovery. It is unlikely that an appraisal well will be drilled in 2010.

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 2009.

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 the potential commerciality.

Block Oza (Within OML 11): Development

(Hardy 20 per cent interest)

2009 Operations

The Oza joint venture has made some progress in 2009. The joint venture received delivery of over 34 km length of pipe for the tie-in of the Oza field to the SPDC operated Isimiri flow station. The operator is in advanced stages of completing the final FEED study and other regulatory and community approvals. Field operations are expected to commence in the first half of 2010.

Background

The Oza Field is located onshore in the north western part of OML 11, near Port Harcourt and covers an area of 20 km2. The Oza field is subject to a farm-out agreement between NNPC, SPDC, Elf Petroleum Nigeria Limited and AGIP as farmor and Milennium as farmee. The terms of this agreement are for an initial five-year period subject to an extension of the Oza farm-out agreement approved by the Nigerian Department of Petroleum Resources (DPR).

The Oza field has cumulatively produced approximately 1.0 MMstb from four open zones in three wells targeting three reservoirs, M5.0, M1.0 and M2.2, with the principal reservoir being M5.0. At present, Oza has three suspended wells in the field. In 2007 the Oza joint venture successfully executed a flow test of the Oza 4 well. The flow rates averaged approximately 600 stbd of oil with a gas to oil ration (GOR) of 5,466 scf/stb.

Block Atala (Within OML 46): Development

(Hardy 20 per cent interest)

2009 Operations

In 2009, the Atala joint venture continued to struggle to secure the appropriate equipment to undertake the planned re-entry programme for the Atala-1 well.

The original marginal field award was subject to review in November 2009. Extension of the Atala licence is contingent on the Nigerian authorities believing that sufficient progress has been made over the initial term to merit an extension. As such, the operator, along with a consortium of other Niger delta marginal field operators, has requested an extension due to equipment constraints and various other circumstances that have frustrated efficient progress of work programmes over the initial term.

Background

Atala is located within OML 46 which is situated within a mangrove swamp on the Dodo River, a coastal area of north west Bayelsa State. The concession area is 34 km2. The Atala field was discovered in 1982 with the drilling of the Atala-1 well to a total depth of 4,058 m. Hydrocarbons were encountered and the well was cased but not tested or completed. The Atala field is subject to a farm-out agreement between NNPC, SPDC, Elf Petroleum Nigeria Limited and Nigerian AGIP Oil Company Limited as farmor and Bayelsa as farmee. The terms of this agreement are for an initial five-year period from 27 April 2004, subject to an extension of the term of the Atala Farm-out Agreement if approved by the Nigerian Department of Petroleum Resources.

Yogeshwar Sharma

Chief Operating Officer

and Chief Executive Officer Designate

3 March 2010

Risk and Uncertainties

As an oil and gas exploration and production company with operations concentrated in India, Hardy is subject to a variety of business risks. Outlined below is a description of the principal risk factors that may affect the Group's business. Such risk factors are not presented in any assumed order of priority. Any of the risks, as well as the other risks and uncertainties discussed in this document, could have a material adverse effect on our 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.

General Exploration, Development and Production Risks

The Group's strategy is predominantly driven by the exploration, exploitation, appraisal, development and production of its existing assets. There are risks inherent in the exploration, exploitation, appraisal, development and production of oil and gas reserves and resources. Whilst the rewards can be substantial, there is no guarantee that exploration will lead to commercial discoveries. Risks such as cost overruns in drilling, delays in execution, technical difficulties, lack of access to key infrastructure, adverse weather conditions, environmental hazards, industrial accidents, occupational and health hazards, technical failures, labour disputes, unusual or unexpected geological formations, explosions and other acts of God are inherent to the business. Although in some cases these represent insurable risks, the Group may also become subject to other hazards (including pollution and oil seepage liability) against which it is not insured or is under insured. The occurrence of any of these incidents can result in the Group's current or future project target dates for drilling or production being delayed or interrupted, increased capital expenditure and production costs and result in liability to the contractor or operator of the field.

Key Risks for 2010

Several of Hardy's blocks have been retained via appraisal and are no longer in the exploration phase. In the event that the joint venture concludes that a discovery is sub-commercial then the corresponding block may be relinquished. Upon relinquishment the Company will no longer retain a commercial interest in the block. Relinquishment may result in the Company values on the balance sheet being revised downward.

With respect to Hardy's Ganesha (CY-OS/2) non-associated natural gas discovery, the Company has presented a case to the Directorate General of Hydrocarbons that supports our claim of entitlement to a licence extension. In the absence of a resolution in our favour, in the near future, we intend to refer the dispute for sole expert or conciliation and arbitration.

The Company's exploration plans comprise activities primarily on non-operated blocks. Subsequently the timing of commencement of activities may not commence as currently forecast. The exploration focus of the Company's 2009 work programme may result in the failure to discover hydrocarbons in commercial quantities.

The status of several of the Company's licences are either approaching or have exceeded the contracted term. These licences can be extended through various government approvals however there is no certainty that these extensions will be granted. Should an extension not be received then the Company will no longer have a commercial interest in the blocks and may be subject to non-performance penalties.

Clear Risk Identification

The table below sets out the general long-tem risks facing Hardy, their potential impact and mitigation strategies developed. Risks are grouped into four main categories: strategic; financial; operational; and external. Effective risk management is critical to achieving our strategic objectives and protecting our people and reputation. Hardy manages and mitigates its risks by maintaining a balanced portfolio, through compliance with the terms of its licences and application of policies and procedures appropriate for an international oil and gas company of its size and scale and through the recruitment and retention of skilled personnel throughout its business.

Risk Category	Mitigation

Strategic risk	Ineffective or poorly executed strategy fails to create shareholder value
Ineffective mix of oil and gas interests	Geographical focus on single region (India) with interests in several autonomous sedimentary basins comprising interests in difference geographical region.
Organic and acquisition - led growth	Regular review of capital investment programmes and limiting allocation to high impact exploration. Board approval required for all annual exploration programmes, acquisitions and divestitures
Inefficient capital allocation	Comprehensive annual budgeting process covering all material expenditures. Annual budget dated an approved by the Board.
Ineffective management processes	Policies and procedures appropriate for an exploration and production company of Hardy's scale and size.
Loss of key staff/succession planning	Remuneration policies to attract and retain staff (employee stock options, annual review, etc), and specific development and training policies implemented.

Financial risk	Assets performance and excessive leverage results in the Group unable to meet its financial obligations
Industry cost inflation	Asset joint operating agreement mandates rigorous contracting procedures with competitive tendering. Inflationary pressures will persist in high commodity price environment.
Capital structure	Conservative approach to debt/equity financing of development projects. Exploration and appraisal activities strictly equity financed.
Uninsured events	Comprehensive insurance programme.
Underperforming assets	Conservative forecasting in the budgeting process. Development of the additional field's (Oza) to reduce dependence on PY-3
Cost overrun	Main capital expenditures incurred via drilling offshore exploration wells. Lower working interest and maintaining strong working capital position mitigates against operations exceeding budgeted number of drilling days.


Operational risk	Operational event impacts staff, contractors, communities or the environment leading to loss of reputation and/or revenue
HSE incident	HSE standards set and monitored regularly across the Group (policies, procedures and performance discussed further in CPR section of report)
Security incident	Ongoing collaboration with Navy and Coast Guard Services, Ministry of Shipping, Ministry of Home Affairs, Ministry of Defence. Periodic offshore security incident simulation exercises.
Key development failure	Technical, financial and Board approval for all projects and quarterly progress reports provided to the Board.
Failure to secure equipment, services and resources	Rigorous contract and procurement procedures implemented internally and required by joint operating agreements. Long-term planning required to resource projects on a timely basis. The Company has limited influence on procurement of equipment services and resources for non-operator assets.
Sustained exploration failure	Effective portfolio management (low interest, many assets) comprise with rigorous review and implementation of best practice exploration processes and techniques. Internal expertise review process prior to Board approval.
Hostile acquisition	Robust defence strategies against hostile acquisitions. Effective and continuous communication with shareholders.

External risk	The overall external political, industry or market environment may negatively impact the Company's ability to independently manage and grow its business
Political risk and fiscal change	Develop sustainable relationships with governments and communities. Indian PSC include fiscal stability clauses. Actively collaborate with industry groups to formulate and communicate interests to government authorities.
Lack of control of keys assets	Joint venturing with partners and governments. Proactive formal and informal communications to convey corporate interests and mandates.
Corporate governance failings	Regular review of compliance requirements and ongoing consultation with legal and financial advisors and audit committee.
Shareholder sentiment	Communicate with investors on a regular basis providing transparent and timely information. Effectively convey and execute corporate strategy
Oil and gas price volatility	Conservative planning and forecasting of future oil prices. The Company's single producing asset and PSC terms limit the practicality to implement financial instruments to mitigate volatility.
Global capital market environment	The Board regularly reviews 24-month capital requirement forecasts. Develop long-term relationships with financial institutions.
Capital default of joint venture partners	Senior management monitors the financial status of the Company's joint venture partners to mitigate any unforeseen funding issues.

HARDY OIL AND GAS plc

Consolidated Income Statement

For the year ended 31 December 2009

		2009	2008
	Notes	US$	US$

Revenue	3	7,687,355	17,306,042

Cost of sales
Production costs	4	(5,661,574)	(7,523,972)
Depletion		(1,078,839)	(1,521,919)
Decommissioning charge		(104,859)	(151,174)
Gross profit		842,083	8,108,977
Administrative expenses		(8,974,255)	(9,847,526)

Operating loss		(8,132,172)	(1,738,549)
Gain on sale of investment		-	12,953,064
Interest and investment income		261,672	1,320,189
Finance costs		(71,378)	(91,204)

(Loss) profit before taxation		(7,941,878)	12,443,500
Taxation		1,424,702	(4,971,144)
(Loss) profit for the year		(6,517,176)	7,472,356

(Loss) earnings per share
Basic	7	(0.10)	0.12
Diluted	7	(0.10)	0.11

HARDY OIL AND GAS plc

Consolidated Statement of Comprehensive Income

For the year ended 31 December 2009

	2009	2008
	US$	US$

(Loss) profit for the year	(6,517,176)	7,472,356
Other comprehensive income (loss)
Reclassification of gain included in profit or loss	-	(12,354,477)
Reclassification of deferred tax on gain	-	3,441,945
	-	(8,912,532)

Total comprehensive loss for the year	(6,517,176)	(1,440,176)

HARDY OIL AND GAS plc

Consolidated Statement of Changes in Equity

For the year ended 31 December 2009

Share capital

US$

premium

US$

Shares to be issued

US$

Retained earnings

US$

Other reserves

US$

Total

US$

At 1 January 2008

622,625

93,101,579

2,501,590

38,857,499

8,912,532

143,995,825

Changes in equity for the year 2008

Total comprehensive income for the year

7,472,356

(8,912,532)

1,440,176

Share based payment

1,425,280

Share options exercised

383

80,001

80,384

Issue of share capital

202

170,358

170,560

At 31 December 2008

623,210

93,351,938

3,926,870

46,329,855

144,231,873

Changes in equity for the year 2009

Total comprehensive loss for the year

(6,517,176)

Share based payment

2,630,838

Issue of share capital

62,090

15,764,184

15,826,274

Issue expenses

(640,198)

At 31 December 2009

685,300

108,475,924

6,557,708

39,812,679

155,531,611

Other reserves represented the gain on past revaluation of an available for sale investment which was transferred to profit and loss on disposal.

HARDY OIL AND GAS plc

Consolidated Statement of Financial Position

As at 31 December 2009

	Notes	2009	2008
		US$	US$
Assets
Non-current assets
Property, plant and equipment	8	10,046,762	8,477,099
Intangible assets - exploration	9	134,725,547	124,013,261
Intangible assets - others		46,144	111,640
Site restoration deposit		3,630,471	3,211,830
Total non-current assets		148,448,924	135,813,830

Current assets
Inventories		2,453,998	3,736,437
Trade and other receivables		3,822,520	4,087,719
Short term investments	11	20,505,130	22,010,291
Cash and cash equivalents		10,036,678	8,139,314
Total current assets		36,818,326	37,973,761

Total assets		185,267,250	173,787,591

Equity and liabilities
Equity attributable to owners of the parent
Share capital	12	685,300	623,210
Share premium		108,475,924	93,351,938
Shares to be issued		6,557,708	3,926,870
Retained earnings		39,812,679	46,329,855
Total equity		155,531,611	144,231,873

Non-current liabilities
Provision for decommissioning		4,500,000	4,500,000
Provision for deferred tax		9,872,917	11,297,619
Total non-current liabilities		14,372,917	15,797,619
Current liabilities
Trade and other payables		15,362,722	13,758,099

Total current liabilities		15,362,722	13,758,099

Total liabilities		29,735,639	29,555,718

Total equity and liabilities		185,267,250	173,787,591

HARDY OIL AND GAS plc

Consolidated Statement of Cash Flows

For the year ended 31 December 2009

		2009	2008
	Notes	US$	US$

Operating activities
Cash flow (used in) from operating activities	5	(1,000,877)	2,065,776
Taxation paid		(10,088)	(1,373,117)
Net cash (used in) from operating activities		(1,010,965)	692,659

Investing activities

Expenditure on property, plant and equipment		(2,853,122)	(6,802,348)
Expenditure on intangible assets - exploration		(10,712,286)	(24,728,727)
Purchase of intangible assets - others		-	(3,841)
Purchase of other property, plant and equipment		(8,773)	(117,097)
Purchase of investment		-	(13,184,387)
Sale of investment		-	41,378,216
Site restoration deposit		(418,641)	157,990
Short-term investments		1,505,161	(22,010,291)
Net cash (used in) investing activities		(12,487,661)	(25,310,485)

Financing activities
Interest and investment income		281,292	1,520,555
Finance costs		(71,378)	(91,204)
Issue of shares		15,186,076	170,741
Net cash from financing activities		15,395,990	1,600,092

Net increase (decrease) in cash and cash equivalents		1,897,364	(23,017,734)

Cash and cash equivalents at the beginning of the year		8,139,314	31,157,048

Cash and cash equivalents at the end of the year		10,036,678	8,139,314

HARDY OIL AND GAS plc

Notes to the Consolidated Financial Statements Year ended 31 December 2009

1. Accounting Policies

The following accounting policies have been applied in preparation of consolidated financial statements of Hardy Oil and Gas plc ("Hardy" or the "Group").

a) Basis of Measurement

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

b) Going Concern

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

c) Basis of Preparation

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

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

IFRS 1 First time adoption of International Financial Reporting Standards (revised 2008)

IFRS 3 Consolidated financial statements (revised 2008)

IFRS 9 Financial instruments (replacement of IAS 39) *

Amendments to IFRS 1 Additional Exemptions for First-time Adopters*

IFRS 1 Amendment - Limited exemption from IFRS 7 Disclosures for First-time Adopters*

IFRS 2 Amendment - Group Cash-settled Share-based Payment Transactions*

IFRS 7 Improving Disclosures about Financial Instruments Amendments to IFRS 7 Financial Instruments: Disclosures

Amendment to IAS 32 Classification of Rights Issues

IAS 24 (Revised) Related Party Disclosures*

IAS 39 Financial instruments: recognition and measurement (Amendment) - eligible hedged items

IFRIC 17 Distribution of non-cash assets to owners

IFRIC 18 Transfer of assets from customers

IFRIC 19 Extinguishing financial liabilities with equity instruments*

IFRIC 14 (Amendment) Prepayments of a minimum funding requirement*

Pronouncements marked '*' have not yet been adopted by the European Union.

In addition, there are certain requirements of Improvements to IFRSs which are not yet effective.

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

d) Functional and Presentation Currency

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

e) Basis of Consolidation

The consolidated financial statements include the results of Hardy and its subsidiary undertakings. The Consolidated Income Statement, the Consolidated Statement of Comprehensive Income and 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.

f) Revenue and Other Income

Revenue represents the sale value of the Group's share of oil which excludes the profit oil sold and paid to the Government as a part of profit sharing in the year, tariff, and income from technical services to third parties if any. Revenues are recognized when crude oil has been lifted and title has been passed to the buyer or when services are rendered.

g) Oil and Gas Assets

i) Exploration and Evaluation Assets

Hardy follows the full cost method of accounting for its oil and gas assets. Under this method, all expenditures incurred in connection with, and directly attributable to, the acquisition, exploration and appraisal having regard to the requirements of IFRS 6 'Exploration for and Evaluation of Mineral Resources' are accumulated and capitalised in two geographical cost pools, which are not larger than a segment: India and Nigeria.

The capitalised exploration and evaluation costs are classified as intangible assets - exploration which includes the licence acquisition, exploration and appraisal costs relating either to unevaluated properties or properties awaiting further evaluation but do not include costs incurred prior to having obtained legal right to explore an area, which costs are expensed directly to the income statement as they are incurred.

Intangible exploration and evaluation cost relating to each licence or block remain capitalised pending a determination of whether or not commercial reserves exists. Commercial reserves are defined as proven and probable on a net entitlement basis.

When a decision to develop these properties is taken or there is evidence of impairment, the costs are transferred to the cost pools within development/producing assets when the commercial reserves attributable to the underlying asset have been established.

ii) Oil and Gas Development and Producing Assets

Development and production assets are accumulated on a field by field basis. These comprise of the cost of developing commercial reserves discovered to put them on production and the exploration and evaluation costs transferred from intangible exploration and evaluation assets, as stated in policy above. In addition, interest payable and exchange differences incurred on borrowings directly attributable to development projects, if any, and assets in the production phase, as well as cost of recognizing provision for future restoration and decommissioning, are 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. Future decommissioning costs are estimated and stated at an amount representing the costs which would be incurred should decommissioning occur at the balance sheet date and the estimates are reassessed each year. The provision is assessed at prices prevailing at the balance sheet date and, accordingly, it is not appropriate to discount this provision. The decommissioning asset is included within the property, plant and equipment with the cost of the related assets installed and is adjusted for any revision to the decommissioning costs and the provision thereof. The amortisation of the asset, calculated on a unit of production basis based on proved and probable reserves, is shown as "Decommissioning charge" in the income statement.

iv) Disposal of Assets

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

h) Depletion and Impairment

i) Depletion

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

ii) Impairment

Exploration assets are reviewed regularly for indications of impairment, if any, where circumstances indicate that the carrying value might not be recoverable. In such circumstances, if the exploration asset has a corresponding development/producing cost pool, then the exploration costs are transferred to the cost pool and depleted on unit of production. In cases where no such development/producing cost pool exists, the impairment of exploration costs is recognised in the income statement. 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, then the difference is recognised in the income statement as impairment.

i) Property, Plant and Equipment

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

	Annual rate (%)	Depreciation method
Leasehold improvements	over lease period	Straight line
Furniture and fixtures	20	Straight line
Information technology and computers	33	Straight line
Other equipment	20	Straight line

j) Intangible Assets

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

Annual rate (%)

Depreciation method

Computer software

Straight line

k) Investments

Investments in publicly traded securities are treated as available for sale and are recognized at fair values based upon the quoted market prices on the balance sheet date in other reserves. On disposal of an investment, the cumulative realised gain or loss is recognised in the income statement.

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

l) Short Term Investments

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

m) Inventory

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

n) Financial instruments

Financial assets and financial liabilities are recognised at fair value in the Group's balance sheet based on the contractual provisions of the instrument.

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

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

o) Equity

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

p) Taxation

The tax expense represents the sum of current tax and deferred tax.

Current tax is based on the taxable profit of the year. Taxable profit differs from net profit as reported in the income statement as it excludes certain 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 balance sheet date.

Deferred tax is the tax expected to be payable or recoverable on differences between the carrying amounts of assets and liabilities in the financial statements and the corresponding tax bases used in the computation of taxable profit, and is accounted for using the liability method.

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 balance sheet date, where transactions or events have occurred at that date that will result in an obligation to pay more or a right to pay less or to receive more tax.

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

q) Foreign Currencies

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

Rates of exchanges are as follows:

31 December

2009

31 December

2008

£ to US$

1.6154

1.4626

US$ to Indian Rupees

46.67

48.52

r) Leasing Commitments

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

s) Share Based Payments

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

2. Critical Accounting Estimates and Judgements

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 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 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 offshore the east coast of India. Intangible assets include an amount of US$83,469,418 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 Government of India (GOI) has been requested to extend the block for appraisal and declaration of commerciality for its gas discovery until 7 January 2012.

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. Directorate General of Hydrocarbons (DGH) has informed the Company that in their opinion the discovery is classified as an oil discovery and not a non-associated natural gas (NANG) discovery.

The Company has obtained third party legal and technical opinions that support the Company's view that the discovery is NANG. The Group continues to be in an ongoing dialogue with the GOI and believes that it will be successful in obtaining the extension of its licence in block CY-OS/2 until 7 January 2012. In the absence of a resolution in its favour in the near future, Hardy intends to refer the dispute for sole expert or conciliation and arbitration.

The Group believes that it will be successful in obtaining the extension of its licence in block CY-OS/2 until 7 January 2012. 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 the balance sheet date. In the event that the Group's application for an extension was to be unsuccessful, the capitalized expenditure will be subject to impairment testing.

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 advancements 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. Segment Analysis

The Group is organised into three business units: India, Nigeria and United Kingdom. India business unit is operated by its subsidiary undertaking Hardy Exploration & Production (India) Inc. Nigeria business unit is operated by Hardy Oil Nigeria Limited. Hardy Oil and Gas plc operates in the United Kingdom.

India business unit focuses on exploration and production of oil and gas assets in India. Nigeria business unit focuses on exploration and production of oil and gas assets in Nigeria. Management monitors these business units separately for resource allocation, decision making and performance assessment.

	2009 US$
	India	Nigeria	UK	Inter-segment eliminations	Total
Revenue
Oil sales	7,687,355	-	-	-	7,687,355
Management fees	-	-	180,000	(180,000)	-
	7,687,355	-	180,000	(180,000)	7,687,355
Operating loss	(2,967,105)	(590,071)	(4,574,996)		(8,132,172)
Interest income	142,801	-	1,401,316	(1,282,445)	261,672
Finance costs	(1,202,591)	(151,232)	-	1,282,445	(71,378)
Loss before taxation	(4,206,895)	(741,303)	(3,173,680)	180,000	(7,941,878)
Taxation	323,233	-	1,101,469	-	1,424,702
Loss for the year	(3,883,662)	(741,303)	(2,072,211)		(6,517,176)
Segment assets	154,454,229	4,407,428	26,405,593		185,267,250
Inter corporate loan	-	-	97,576,000	(97,576,000)	-
Segment liabilities	26,392,711	9,708	3,333,220		29,735,639
Inter corporate borrowings	(90,368,000)	(7,208,000)		97,576,000	-
Capital expenditure	13,566,820	-	7,361		13,574,181
Depletion, depreciation and amortisation	1,279,846	33,926	143,956	-	1,357,728

	2008 US$
	India	Nigeria	UK	Inter-segment eliminations	Total
Revenue
Oil sales	18,748,999	-	-	-	18,748,999
Profit oil to government	(2,311,862)	-	-	-	(2,311,862)
Management fees	-	-	180,000	(180,000)	-
Other income	-	-	868,905		868,905
	16,437,137	-	868,905	(180,000)	17,306,042
Operating profit (loss)	3,494,875	(271,740)	(4,961,684)		(1,738,549)
Interest income	351,152	-	3,159,127	2,190,090	1,320,189
Finance costs	(2,057,559)	(223,735)	-	(2,190,090)	(91,204)
Gain on sale of investment	-	-	12,953,064		12,953,064
Profit (loss) before taxation	1,788,468	(495,475)	11,150,507		12,443,500
Taxation	(1,372,230)	-	(3,598,914)		(4,971,144)
Profit (loss) for the year	416,238	(495,475)	7,551,593		7,472,356
Segment assets	146,174,240	4,230,902	23,382,449		173,787,771
Inter corporate loan	-	-	86,788,000	(86,788,000)	-
Segment liabilities	25,279,783	2,194	4,273,740		29,555,717
Inter corporate borrowings	(80,400,000)	(6,388,000)	-	86,788,000	-
Capital expenditure	30,948,918	686,040	17,056		31,652,014
Depletion, depreciation and amortisation	1,837,481	48,507	70,594	-	1,956,582

The Group is engaged in one business activity, the exploration and production and 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. The revenue by destination is not materially different from the revenue by origin.

4. Cost of Sales

Production cost included in the cost of sales consists of:

	2009 US$	2008 US$
Opening stock of crude oil	1,843,226	1,132,065
Cost of crude oil produced and saved	3,818,348	8,235,133
Closing stock of crude oil	-	(1,843,226)
Production cost	5,661,574	7,523,972

5. Reconciliation of Operating Loss to Operating Cash Flows

	2009 US$	2008 US$
Operating loss	(8,132,172)	(1,738,549)
Depletion and depreciation	1,252,869	1,805,408
Decommissioning charge	104,859	151,174
Share based payments charges	2,657,572	1,429,736
	(4,116,872)	1,647,769
Decrease (increase) in inventory	1,282,439	(1,032,522)
Decrease (increase) in trade and other receivables	228,933	(2,676,392)
Increase in trade and other payables	1,604,623	4,126,921
Net cash flow (used in) operating activities	(1,000,877)	2,065,776

6. Staff Costs

2009

US$

2008

US$

Wages and salaries

Social security costs

Share based payments charge

3,398,707

179,520

2,789,471

3,830,118

214,537

2,632,812

6,367,698

6,677,467

Staff costs include Executive Directors' salaries, fees, benefits and share based payments, and is 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:

	2009	2008
Management and administration	25	27
Operations	26	24
	51	51

7. (Loss) Earnings Per Share

(Loss) earnings per share are calculated on a loss of US$ 6,517,176 for the year 2009 (profit for 2008: US$ 7,472,356) on a weighted average of 66,506,242 Ordinary Shares for the year 2009 (2008: 62,287,526).

The diluted (loss) earnings per share are calculated on a loss of US$ 6,517,176 for the year 2009 (profit for 2008: US$ 7,472,356) on a weighted average of 71,258,343 Ordinary Shares for the year 2009 (2008: 66,994,627). For the year 2008 the weighted average shares are calculated after giving impact to dilutive potential Ordinary Shares of 4,302,101 relating to share options after excluding 405,000 options wherein the strike price exceeds the average market price of the shares of the Company. As there is a loss in 2009, no dilutive potential is considered for computing the loss per share.

8. Property, Plant and Equipment

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

	Oil and gas assets US$	Other fixed assets US$	Total US$
Cost At 1 January 2008	25,996,319	2,572,706	28,569,025
Additions	6,802,348	117,097	6,919,445
At 1 January 2009	32,798,667	2,689,803	35,488,470
Additions	2,853,122	8,773	2,861,895
Deletions	-	(89,304)	(89,304)
At 31 December 2009	35,651,789	2,609,272	38,261,061
Depletion, depreciation and amortisation
At 1 January 2008	22,903,662	2,289,900	25,193,562
Charge for the year	1,673,093	144,716	1,817,809
At 1 January 2009	24,576,755	2,434,616	27,011,371
Charge for the year	1,183,698	108,534	1,292,232
Deletions	-	(89,304)	(89,304)
At 31 December 2009	25,760,453	2,453,846	28,214,299
Net book value at 31 December 2009	9,891,336	155,426	10,046,762
Net book value at 31 December 2008	8,221,912	255,187	8,477,099

9. Intangible Assets - Exploration

	India US$	Nigeria US$	Total US$
Costs and net book value
At 1 January 2008	96,821,650	2,462,884	99,284,534
Additions	24,094,090	634,637	24,728,727
At 1 January 2009	120,915,740	3,097,521	124,013,261
Additions	10,712,286	-	10,712,286
At 31 December 2009	131,628,026	3,097,521	134,725,547

The Group holds a 75 per cent participating interest in the block CY-OS/2 in offshore the east coast of India. Intangible assets include an amount of US$ 83,469,418 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 Government of India (GOI) has been requested to extend the block for appraisal and declaration of commerciality for its gas discovery until 7 January 2012.

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 the Company that in their opinion the discovery is classified as an oil discovery and not a non associated natural gas (NANG) discovery.

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.

10. Members of the Group

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

·; Hardy Exploration & Production (India) Inc. incorporated under the Laws of State of Delaware, United States of America.

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

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

All members of the Group are engaged in the business of exploration for and production of oil and gas and all are included in the consolidated financial statements.

11. Short Term Investments

	2009 US$	2008 US$
HSBC US$ Liquidity Fund Class-A	19,863,924	17,795,890
HSBC £ Liquidity Fund Class-A	641,206	4,214,401
	20,505,130	22,010,291

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

12. Share Capital

	Number US$0.01 Ordinary Shares "000"	US$
Authorised Ordinary Shares
At 1 January 2008	200,000	2,000,000
At 1 January 2009	200,000	2,000,000
At 31 December 2009	200,000	2,000,000
Allotted, issued and fully paid Ordinary Shares
At 1 January 2008	62,262,535	622,625
Share options exercised during the year	38,330	383
Shares issued during the year	20,182	202
At 1 January 2009	62,321,047	623,210
Shares issued during the year	6,208,997	62,090
At 31 December 2009	68,530,044	685,300

Shares issued in the year were as a result of the placing in April 2009. Ordinary Shares issued have equal voting and other rights with no guarantee to dividend or other payments.

13. Financial Instruments

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

Financial assets

Primary financial instruments	Book value 2009 US$	Fair value 2009 US$$	Book value 2008 US$	Fair value 2008 US$
Short term investments	20,505,130	20,505,130	22,010,291	22,010,291
Cash and short term deposits	10,036,678	10,036,678	8,139,314	8,139,314
Site restoration deposit	3,630,471	3,630,471	3,211,830	3,211,830
	34,172,279	34,172,279	33,361,435	33,361,435

Financial liabilities

Primary financial instruments

Book value

2009

US$

Fair value

2009

US$$

Book value

2008

US$

Fair value

2008

US$

Accounts payable

(15,362,722)

(13,758,099)

Provisions for

decommissioning

(4,500,000)

(19,862,722)

(18,258,099)

All of the above financial assets and liabilities are current at the balance sheet dates.

This information is provided by RNS

The company news service from the London Stock Exchange

END

FR LFFVLVAIVIII

Date		Source	Headline
21st Feb 2020	4:40 pm	RNS	Second Price Monitoring Extn
21st Feb 2020	4:35 pm	RNS	Price Monitoring Extension
30th Jan 2020	8:50 am	RNS	Holding(s) in Company
23rd Jan 2020	4:40 pm	RNS	Second Price Monitoring Extn
23rd Jan 2020	4:35 pm	RNS	Price Monitoring Extension
22nd Jan 2020	12:43 pm	RNS	Director Changes and Notice to De-List
21st Jan 2020	3:07 pm	RNS	OFFER CLOSED
8th Jan 2020	7:00 am	RNS	Update of Offer
8th Jan 2020	7:00 am	RNS	Response to First Closing
6th Jan 2020	3:19 pm	RNS	Offer Unconditional in All Respects
23rd Dec 2019	7:00 am	RNS	Response to Offer
16th Dec 2019	12:48 pm	RNS	Form 8.3 - Amendment: Hardy Oil & Gas plc
13th Dec 2019	12:07 pm	RNS	Form 8.3 - Hardy Oil & Gas plc
13th Dec 2019	9:03 am	RNS	Form 8.3 - Hardy Oil and Gas plc
13th Dec 2019	9:02 am	RNS	Offer Document Posted
12th Dec 2019	9:57 am	RNS	Form 8.3 - Hardy Oil and Gas
12th Dec 2019	7:00 am	RNS	Half-year Report
11th Dec 2019	6:05 pm	RNS	Form 8.3 - Hardy Oil & Gas
9th Dec 2019	3:00 pm	RNS	Form 8.3 - Hardy Oil and Gas Plc
9th Dec 2019	2:40 pm	RNS	Form 8.3 - [Hardy Oil and Gas]
9th Dec 2019	11:29 am	RNS	Form 8 (OPD) (Hardy Oil and Gas plc)
4th Dec 2019	7:34 am	RNS	Form 8.3 - Hardy Oil & Gas Plc
28th Nov 2019	11:06 am	RNS	Form 8 (OPD) (Blake Holdings Limited)
27th Nov 2019	1:30 pm	RNS	Form 8.3 - Hardy Oil & Gas plc
26th Nov 2019	7:00 am	RNS	Re Mandatory Offer
25th Nov 2019	4:40 pm	RNS	Second Price Monitoring Extn
25th Nov 2019	4:35 pm	RNS	Price Monitoring Extension
25th Nov 2019	4:33 pm	RNS	MANDATORY CASH OFFER by BLAKE HOLDINGS LIMITED
30th Oct 2019	7:00 am	RNS	Transfer of Listing
23rd Oct 2019	5:30 pm	RNS	Hardy Oil & Gas
21st Oct 2019	7:00 am	RNS	Board Changes
2nd Oct 2019	9:51 am	RNS	Completion of Sale of HEPI
1st Oct 2019	12:46 pm	RNS	Result of EGM
30th Sep 2019	5:53 pm	RNS	Result of AGM
22nd Aug 2019	4:28 pm	RNS	Proposed Disposal of HEPI, Notice of EGM
22nd Aug 2019	3:12 pm	RNS	Annual Report and Notice of Annual General Meeting
22nd Jul 2019	5:00 pm	RNS	UPDATE ON THE OFFERS FOR THE ACQUISITION OF HEPI
19th Jul 2019	5:36 pm	RNS	Holding(s) in Company
19th Jul 2019	5:20 pm	RNS	Holding(s) in Company
15th Jul 2019	1:57 pm	RNS	UPDATE ON CONDITIONAL SALE OF HEPI
10th Jul 2019	12:19 pm	RNS	Holding(s) in Company
1st Jul 2019	5:24 pm	RNS	Conditional Sale of HEPI
27th Jun 2019	7:00 am	RNS	Final Results
24th May 2019	12:38 pm	RNS	Holding(s) in Company
16th Apr 2019	12:34 pm	RNS	Holding(s) in Company
2nd Apr 2019	10:25 am	RNS	Block listing Interim Review
6th Feb 2019	4:40 pm	RNS	Second Price Monitoring Extn
6th Feb 2019	4:35 pm	RNS	Price Monitoring Extension
31st Jan 2019	12:02 pm	RNS	Price Monitoring Extension
30th Jan 2019	4:40 pm	RNS	Second Price Monitoring Extn

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